Macro

Northwest European olefin producers have largely shifted to naphtha and propane as a marginal feedstock for their steam crackers, turning down more expensive butane, market sources said this week.

"Butane is definitely out [of the cracking pool], it is going to blenders," a petrochemical end-user said Tuesday, while another added that propane was still in.

This comes as gasoline blenders' incremental buying interest has tightened both the light naphtha market as well the butane barge complex in the Amsterdam-Rotterdam-Antwerp region as well as Northwest European butane seagoing CIF coasters.

"The naphtha market has been stronger due to blending demand for West Africa and the US Atlantic Coast," another market participant said, adding it had been a combination of factors with US gasoline commercial stocks at record lows, higher demand for the motor product and issues with US Colonial Pipeline Lines 1 and 2 -- which bring refined products from the Gulf Coast to the Midwest and East Coast.

he CIF Northwest Europe physical cargo rose $10.75/mt on the day to be assessed sat an almost one-year high of $442.75/mt Wednesday. The last time it was assessed higher was October 10, 2015,according to S&P Global Platts data In terms of physical premium, the CIF NWE naphtha cargo was assessed at $6.50/mt above the front-month swap, up from $4.75/mt the previous day, which represents the highest premium in over three months.

In the meantime, butane barges were assessed at 101.4% CIF ARA versus physical naphtha Wednesday and CIF coasters stood at 96% relative to naphtha. This is both well above the typical threshold of around 90% below which olefin producers prefer to crack gas as opposed to naphtha.

Having said this, butane prices have been retreating over the last days as gasoline blenders focused on mixed aromatics exports to Asia as opposed to blending of winter specification gasoline. Overall, however, the butane complex should remain a blenders market in the weeks to come. According to one market source, spot demand from blenders should pick up next week again and support prices.

For the time being, however, lower prices saw some olefin producers looking for butane on CIF coasters if offer levels were sufficiently low.

"I think petchems is still buying butane on coasters when they can," a second market source said. This opportunistic buying interest comes as olefin producers are not in a rush to buy with naphtha being an attractive alternative as well as propane, for those with required steam cracker flexibility.

The November propane/naphtha spread -- the difference between the front-month CIF ARA propane swap and the CIF NWE naphtha swap -- widened to minus $93.25/mt Wednesday from minus $90.25/mt Tuesday. This saw the November propane swap valued at 78.6% relative to respective naphtha swap, thus making propane a viable feedstock for crackers with the required flexibility.

Renzi's referendum

This time, though, investors shouldn’t be caught by surprise. A> barometer of online chatter that correctly anticipated most> Britons would opt to quit the European Union is now suggesting> that Italians are so fed up with Prime Minister Matteo Renzi> they are willing to vote on Dec. 4 against a slimmed-down> legislature just to see him sent home.>> This measure of discontent was developed by Predata, a New York-> based predictive analytics firm founded in early 2015. It scours> around 1,000 sources to quantify how much the online activity of> the “Yes” and “No” camps is correlated to the ebb and flow of> overall interest in the referendum.>> Since Sept. 29, when Renzi officially kicked off the referendum> campaigning, Predata’s measure shows “No” gaining ground and> “Yes” plummeting.> These signals include content posted to sites such as> Twitter and Wikipedia by the likes of Basta un Sì (the official> “Yes” campaign) and Beppe Grillo (“No” campaigner and founder of> the anti-establishment Five Star Movement), explained Aaron> Timms, Predata’s director of content. “There’s a sign that ‘No’> at this stage is just a more competent and efficient digital> outfit than ‘Yes’ is,” Timms said.> A look at Predata’s Brexit signals — where a less-> organized “Leave” camp consistently dominated the online debate> amid tight polls — suggests a strong starting position for> Italy’s “No” campaign.> “What we do know from the experience with Brexit,” Timms> said, “is that when you have a digital-rich, content-rich> political campaign, the shifting momentum between different> sides can really be a good indicator of where public opinion is> heading in a way that polls can’t necessarily catch up with.”> While not enough to move the Predata dial, Renzi has> intensified his Twitter campaign to woo younger voters, whom> polls say are the most likely to reject the referendum. The> #BastaUnSi (“It takes just one yes”) hashtag, helped by Renzi’s> 2.65 million Twitter followers, had largely prevailed the “No”> camp’s #IoVotoNo hashtag (“I vote no”) up until this week when> it was overtaken in terms of impressions — likes and retweets,> for example — according to data from analytics site Keynote.> Roberto Baldassari, president of pollster Istituto Piepoli,> disagrees that social media is truly representative.> “The ‘No’ vote is ahead but the electorate behind that> camp, in particular the Five Star movement, is very fluid,” he> said. “I think, looking at the trend, that ‘Yes’ is more likely> to win.”>> Almost 40 percent of those surveyed in Piepoli’s latest poll,> which had “No” ahead 54 percent to 46 percent, said they might> switch sides .> “No” led in five of the last six polls, but within the> margin of error. “The recent trend is for the ‘Yes’ vote on the> rise, up four to five points from a month ago,” said Antonio> Noto, Director of IPR Marketing, whose Sept. 30 poll found 40> percent still undecided. This is several times larger, as a> share of respondents, than in the final days before Brexit.> Investors, meanwhile, seem to trust what Predata’s seeing> and that polls won’t ultimately switch in Renzi’s favor. Italian> government bond yields recently climbed to a three-month high> and the spread with equivalent Spanish securities increased to a> two-year high.

Total sells Atotech speciality chemical arm to Carlyle for $3.2 bln

Total has agreed to sell its speciality chemicals arm Atotech for $3.2 billion to private equity firm Carlyle Group, part of a programme under which the French oil company hopes to divest $10 billion worth of non-core assets by 2017.

Total said the sale price was equivalent to 11.9 times 2015 EBITDA earnings for the business which specialises in metallization, panel plating and corrosion protection.

Power imports into UK hit lowest point in three years

Imports of electricity into the UK hit a three year low last month but were offset by increased domestic wind, coal and gas-fired power generation.

The situation arose in September due to outages on the French and Dutch inter-connectors restricted supply.

Platts reported that total electricity imports fell to 1.1 TWh, the lowest recorded since February 2013 when imports were 1 TWh. At the same time last year, total imports reached 1.95 TWh.

The 2 GW UK-France Interconnector was running at half its capacity between September 19-30, and is currently undergoing a planned outage, which began on October 3 for 19 days, National Grid said.

Also in September, the 1 GW Dutch-UK BritNed interconnector operator reduced the link's supply to zero for the annual planned maintenance outage, which started on September 19 and ended on September 21.

Several maintenance outages also reduced nuclear power supplies to 5.72 TWh in September from 5.86 TWh in August, Platts data showed.

Despite the aforementioned events, wind power production rose on the month to 1.73 TWh in September, which was more than 36 per cent higher than 1.27 TWh recorded during the same month last year.

Coal-fired power generation recovered from record lows seen in August to rise to nearly 1 TWh in September, but tumbled 76.6 per cent below last year's levels.

Attached Files

Innogy IPO to be priced at upper end of range

Utility RWE is expected to price the shares of Innogy, which bundles its renewables, network and retail units, at the upper end of the target range, Innogy said on Wednesday, signalling strong demand for Germany's largest IPO since 2000.

Investors will likely pay a price between 35 and 36 euros ($39.29-40.41) per share in the offering, a spokeswoman for Innogy said, the upper end of a 32-36 euro target range communicated last month.

Would-be shareholders are keen on Innogy's high share of regulated businesses, giving them clarity over its profits for several years into the future at a time when interest rates remain at record lows.

Books are covered twice already at a price of 35 euros apiece, a person familiar with the listing said, amounting to orders worth more than 9.7 billion euros. For any IPO to go through smoothly bankers consider it necessary to get bids for twice the volume of shares available.

The person added one large U.S. investment fund alone had placed an order for stock worth more than 700 million euros, following a similar order from asset manager BlackRock, which has committed to buy 940 million euros of Innogy shares.

As part of the IPO, Innogy will issue 55.6 million new shares while parent RWE aims to sell as many as 83.3 million existing shares, valuing the unit at up to 20 billion euros, more than twice RWE's current market capitalisation.

Parent RWE, which will hold at least 75 percent in Innogy following the listing, had already received orders for all of the shares on offer on Sept. 26, the first day of the subscription period. The stock is due to start trading on Friday.

Pityana dubs Zuma “sponsor of corruption” in breathtaking attack

ANGLOGOLD Ashanti chairman, Sipho Pityana, today launched an all-out attack on President Jacob Zuma calling for his immediate departure from office and describing him as a man “who cannot be trusted”.

Pityana was speaking at the Joburg Indaba conference being held in Sandton and he launched his attack on Zuma after being warned from the podium by the speaker ahead of him – deputy minister of mineral resources Godfrey Oliphant – to tone down his comments.

Oliphant said: “You can’t take South Africans to the ballot box. The president has to run his term. If you carry on like that we will return in kind”.

In response Pityana stated flatly: “I have been asked to behave myself but, sorry deputy minister, Zuma must go for the sake of the country. The elephant in the room is a president who lacks integrity; the elephant in the room is a president who is without honour”.

Pityana ended his speech declaring: “We have to seize the moment and save South Africa. I have now committed treason”, and was given a standing ovation by the great majority of the audience.

According to conference chairman, Bernard Swanepoel, Oliphant was not scheduled to address the conference, but had “gatecrashed it” at the last moment.

Pityana described South Africa as a country in crisis on several fronts of which the most pressing was the high level of corruption in government and state enterprises which was now on such a scale it was being referring to as “state capture”.

He described Zuma as “… a president who at best is missing in action and, at worst, he is a leader at the very root of this crisis – one who has abrogated his constitutional duties” as well as “a president who literally laughs off any suggestion that government be held to a higher standard – and, is, in fact, the sponsor-in-chief of corruption”.

He added that: “Our finance minister – a rare example of probity and good governance – a distinguished public servant who is leading the efforts to maintain our investment grade credit rating is hectored and intimidated at every turn. Ratings agencies are sneered at. Businesses are hobbled at any opportunity. The needs of ordinary people are ignored”.

Pityana was also critical about the policy of silence on key national issues such as corruption which had been followed to date by much of the business community.

He commented: “We are at a watershed moment for our young democracy. Many in our leadership – most notably our President – have an agenda that appears – to me at least – to be entirely at odds with addressing the increasingly desperate needs of our country.

“It cannot be business as usual. We need to wake up to what our young students sense already which is that the business community has a vital role to play in saving South Africa.

“Business is present in every home in our country in one way or another yet it is a missing voice in meaningful discourse on the most important issue of the day”.

Attached Files

James Lovelock: Climate change, fracking and lots more

James Lovelock’s parting words last time we met were: “Enjoy life while you can. Because if you’re lucky, it’s going to be 20 years before it hits the fan.” It was early 2008, and the distinguished scientist was predicting imminent and irreversible global warming, which would soon make large parts of the planet uninhabitably hot or put them underwater. The fashionable hope that windfarms or recycling could prevent global famine and mass migration was, he assured me, a fantasy; it was too late for ethical consumption to save us. Before the end of this century, 80% of the world’s population would be wiped out.

His predictions were not easy to forget or dismiss. Sometimes described as a futurist, Lovelock has been Britain’s leading independent scientist for more than 50 years. His Gaia hypothesis, which contends that the earth is a single, self-regulating organism, is now accepted as the founding principle of most climate science, and his invention of a device to detect CFCs helped identify the hole in the ozone layer. A defiant generalist in an era of increasingly specialised study, and a mischievous provocateur, Lovelock is regarded by many as a scientific genius.

Eight years after our previous encounter, he appears to have aged not one bit. At 97, he’s conceived a beautifully illustrated book of essays described as a “tool kit for the future”,The Earth and I, and written the introduction and conclusion; he goes walking every day, his hearing is perfect, his focus forensic and his memory unimpaired. “Yes, why not? I’m writing a fiction book at the moment. It’s tremendous fun, you know.” He applies his holistic philosophy of science to his own health. “I’m a firm believer that if you don’t use it, you lose it – and if you do a lot of walking, and if you use your muscles quite a bit, your brain seems to work as well. You’ve got to look at the whole system, not just bits of it.”

What has changed dramatically, however, is his position on climate change. He now says: “Anyone who tries to predict more than five to 10 years is a bit of an idiot, because so many things can change unexpectedly.” But isn’t that exactly what he did last time we met? “I know,” he grins teasingly. “But I’ve grown up a bit since then.”

Lovelock now believes that “CO2 is going up, but nowhere near as fast as they thought it would. The computer models just weren’t reliable. In fact,” he goes on breezily, “I’m not sure the whole thing isn’t crazy, this climate change. You’ve only got to look at Singapore. It’s two-and-a-half times higher than the worst-case scenario for climate change, and it’s one of the most desirable cities in the world to live in.”

There are various possible explanations for his change of heart. One is that Lovelock is right, and the models on which his former predictions were based were fatally flawed. Another is that his iconoclastic sensibility made revision irresistible. An incorrigible subversive, Lovelock was warning the world about climate change for decades before it began to pay attention, and just when the scientific consensus began to call for intervention to prevent it, he decided we were already too late. But there is a third explanation for why he has shifted his position again, and nowadays feels “laid back about climate change”. All things being equal – “and it’s only got to take one sizable volcano to erupt and all the models, everything else, is right off the board” – he expects that before the consequences of global warming can impact on us significantly, something else will have made our world unrecognisable, and threaten the human race.

Lovelock maintains that, unlike most environmentalists, he is a rigorous empiricist, but it is manifestly clear that he enjoys maddening the green movement. “Well, it’s a religion, really, you see. It’s totally unscientific.” He was once invited to Buckingham Palace, where he told Princess Anne: “Your brother nearly killed me.” Having read that Prince Charles had installed grass-burning boilers at Highgrove, Lovelock had tried one in his house. “It’s supposed to smoulder and keep the place warm; but it doesn’t, because it goes out, and clouds and clouds of smoke come out.” He giggles. “Princess Anne thought this was hilariously funny.”

Lovelock had been trying to heat his old mill in Devon, where he lived for more than 35 years, inventing contraptions in a workshop that resembled a Doctor Who set. He and his wife recently packed up his life’s work and downsized to a remote cottage on Chesil Beach in Dorset, after the bill to heat the mill for just six months hit £6,000. “I remember George Monbiot took me up on it and wrote that it was impossible, that I had to be lying. But I wasn’t lying, I’ve got the figures.” Monbiot doesn’t quite accuse him of lying, in fairness; just of “talking rubbish” and “making wild statements”. In any case, he says that in the US he found he could heat a house for six months, in temperatures of -20C (-4F), for just £60. As a result, he has withering contempt for environmentalists’ opposition to fracking. “You see, gas in America is incredibly cheap, because of fracking,” he says. But what about the risk of triggering earthquakes? He rolls his eyes.

“Sure enough, that’s true, there will be an increase. But they’re tiny little tremors, they would be imperceptible. The only trouble is that you can detect them. The curse of my life has been that I’ve spent a lot of time inventing devices that are exceedingly sensitive. And the moment somebody can detect something, they’re going to attach a number to it, and then they make a fuss about it.” He chuckles, then pauses. “I’m not anti-green in the sense that I’m in favour of polluting the world with every damn thing we make. I think we’ve got to be careful. But I’m afraid, human nature being what it is, the thing gets exaggerated out of all proportion, and the greens have behaved deplorably instead of being reasonably sensible.”

How James Lovelock introduced Gaia to an unsuspecting world

We have learned so much about our home planet in the three decades since James Lovelock wrote Gaia: A New Look at Life on Earth. Has it stood the test of time?

Even more heretical than his enthusiasm for fracking is Lovelock’s passionate support for nuclear power. But, like fracking, he says, it offers only “a stopgap” solution. “Because in the long term, they’ll use up all the uranium.” How long would that take? He pauses to do some quick mental arithmetic, as casually as I might tot up how many pints of milk to grab from Sainsburys.

“Let’s see … I think uranium that is affordable to extract would last about 50 years, something in that range. It might be 100. When you’ve used all that up, you go to thorium, and that would last you three times as long as uranium – so, shall we say, about 200 years?” The most sensible energy solution would be to cover 100 sq miles of the Sahara in solar panels. “It would supply the whole of Europe with all the energy they needed,” but it won’t happen “because it would be so easy for terrorists to go and bugger it up”. So for now, nuclear energy is the only viable option.

But all this, he clarifies cheerfully, is more or less academic. “Because quite soon – before we’ve reached the end of this century, even – I think that what people call robots will have taken over.” Robots will rule the world? “Well, yes. They’ll be in charge.” In charge of us? “Yes, if we’re still here. Whether they’ll have taken over peacefully or otherwise, I have no idea.”

For robots, time happens a million times faster than it does for us. That’s rather wonderful in a way, isn’t it?

He isn’t alone in this view: the influential philosopher Nick Bostrom has persuaded many people that artificial intelligence poses a real threat to the future of humanity; Elon Musk and Stephen Hawking, among others, have called for urgent research to mitigate the risks. Still, when Lovelock outlines this vision, his tone is so matter-of-fact that for a moment I wonder if he’s joking. He isn’t. “We’re already happily letting computers design themselves. This has been going on for some time now, particularly with chips, and it’s not going to be long before that’s out of our hands, and we’ll be standing aside and saying, ‘Oh well, it’s doing a good job designing itself, let’s encourage it.’” Computers will develop independent volition and intuition (“To some extent, they already have”) and become capable of reproducing themselves, and of evolving. “Oh yes, that’s crucial. We’ll have a world where Darwin’s working.” Darwinism doesn’t work now? “Oh no, we’ve temporarily turned Darwinism backwards. I mean, we preserve the ones that would not have survived.”

He pauses, and adds quickly: “Don’t let’s get dangerous on this one. I don’t want this appearing in the Guardian that he just wants all the dumb and the lowlifes wiped out.”

Lovelock doesn’t sound the least bit troubled by the prospect of robots taking over, though, despite the possibility that they will destroy us. “Once they become at all established anywhere, that’s the end, because to robots time happens one million times faster – that’s a fairly exact figure – than it does to us. That’s rather wonderful in a way, isn’t it?”

I ask him to explain. “Well, for a neuron to travel a foot takes a microsecond – which is fairly fast. But for electrons to go down a foot of wire takes a nanosecond. It’s a million times faster, as simple as that. So to a robot, once fully established in that new world, a second is a million seconds. Everything is happening so fast that they have on earth a million times longer to live, to grow up, to evolve, than we do.”

It is possible, he goes on, that human beings may fuse with robots to become a blend of robotic and human tissue (“That’s one route”), but the likelier scenario will be pure robots. Why does he think we’ll go for all-out robots? He shoots me an amused look. “I don’t think we will. I think that they will – that’s the key thing here.”

The implications for climate change are obvious. “The world that they’re going to be comfortable in is wildly different from the one that we feel comfortable in. So once they really get established, they will – with regret – start losing organic life.” Will they care about rising temperatures? “They won’t give a fourpenny fuck about the temperature, because to them the change will be slow, and they can stand quite a big change without any fuss. They could accommodate infinitely greater change through climate change than we can, before things get tricky for them. It’s what the world can stand that is the important thing. They’re going to have a safe platform to live in, so they don’t want Gaia messed about too much.”

James Lovelock: The UK should be going mad for fracking

Notwithstanding his caveats about the dangers of predictions, his confidence in the robotic future he describes is “fairly high. Yes, all sorts of things can happen, but that’s the intuitive feeling I have”. As for our interaction with robots: “Well, it’s going to be very peculiar.” In the classic Frankenstein tradition, will humanity not understand what it has created until it’s too late? “Well, too late is the wrong word. Let’s say, until it has happened.” The phrase “too late”, he explains, implies regret – but whereas the robots might see no use for our continued existence, “maybe we’ve got some special property that they will appreciate. But then, don’t forget, their timescale is a million times different from ours. They’d have a lot of trouble talking to us.” In the same sense that we have trouble talking to ants? “Oh no, it’s much worse than that. It’s really more like us talking to a giant redwood tree. And you never know, they may feel about us the same way as we feel about trees.” They might even, I suggest, want to hug us? Lovelock’s face lights up in delight. “Yes, exactly! Exactly. That’s a good one.”

Lovelock was no less bafflingly cheerful when he believed climate change was about to wipe out 80% of the world’s population. How can he now feel just as sanguine about a global takeover by robots? “One may say: ‘Well, of course, he’s so old he’s stopped having any feelings.’ Not true, I’ll say!” He would have been, he insists, just the same 50 years ago. “And I would hate to think it was an affectation.” He would rather not be called a maverick, because it makes him sound like someone who “makes gadgets in his garage”.

Shippers brace for new rules to cut deadly sulphur emissions

The global shipping industry is bracing for a key regulatory decision that could mark a milestone in reducing maritime pollution, but which could nearly double fuel costs in a sector already reeling from its worst downturn in decades.

The shipping industry is by far the world's biggest emitter of sulfur, with the SOx content in heavy fuel oil up to 3,500 times higher than the latest European diesel standards for vehicles.

To combat such pollution, the International Maritime Organization's (IMO) Marine Environment Protection Committee will meet in London on Oct. 24-28 to decide whether to impose a global cap on SOx emissions from 2020 or 2025, which would see sulfur emissions fall from the current maximum of 3.5 percent of fuel content to 0.5 percent.

"One large vessel in one day can emit more sulfur dioxide than all the new cars that come onto the world's roads in a year," said Thomas Koniordos, head of business line environmental solutions at Norway's Yara International.

Large container ships of 15,000-18,000 TEUs (20-foot equivalent units) consume up to 300 tonnes of high-sulfur fuel a day at sea, while a 300,000 deadweight tonne (DWT) supertanker guzzles up to about 100 tonnes per day. Health experts say sulfur is responsible for deadly heart and lung diseases.

The issue has been brewing for more than a decade and shippers said the industry was now bracing for tighter regulation to be introduced sooner rather than later due to political pressure.

"The decision will likely be a political one - the European Union is pressing strongly for 2020," said Arthur Bowring, managing director of the Hong Kong Shipowners' Association.

EUROPE, CHINA TIGHTEN RULES

The European Union has already agreed that the 0.5 percent sulfur requirement will apply in 2020 within 200 nautical miles (370 km) of EU Member States' coasts, regardless of what the IMO decides.

China, home to the world's busiest container ports, is also demanding cleaner fuels.

Authorities in Shenzhen, the world's third biggest container port, introduced tighter controls this month, demanding that ships calling there do not use fuel with a sulfur content of more than 0.5 percent.

Ship owners can comply with the tighter controls either by switching away from the sludgy and sulfur-rich so-called bunker fuels to diesel or liquefied natural gas (LNG), or by fitting scrubbers to clean exhaust emissions.

A fuel-switch would impose extra costs on an already troubled shipping sector, which has seen high-profile defaults like South Korea's Hanjin as well as cases of stranded ships with crew left onboard ships unpaid and unsupplied.

Using low-sulfur diesel instead of bunker fuel on a very large crude carrier (VLCC) class supertanker would boost fuel costs by around 44 percent from an average of $212 per tonne this year for heavy fuel oil to $379 per tonne for gas oil, according to figures from shipping broker Clarkson.

For traded oil markets, the shift to low-sulfur fuel will "substantially reduce demand for bunkers in the run up to 2020 and increase demand for gasoil and alternative fuels including LNG," said Christopher Haines, head of oil and gas at BMI Research.

Hitachi Construction offers A$689m for Australia’s Bradken

Hitachi Construction Machinery, the world’s biggest maker of giant excavators, made a A$689-million offer to acquire Bradken, an Australian supplier of miningequipment.

The company will offer A$3.25 per share to buy theNewcastle, New South Wales-based company, the Japanese manufacturer said in a statement on Monday. That’s a 34% premium over Bradken’s closing share price on Friday, according to Bloomberg calculations. The offer was recommended by Bradken’s board, according to a separate statement.

The acquisition would enable Hitachi Construction Machinery to supplement its parts business for miningequipment and boost earnings, the Tokyo-based company said. The announcement comes about two months after its larger domestic rival, Komatsu said it agreed to buy US-basedJoy Global for $2.89-billion, signalling the company is optimistic that demand for shovels and drills will rebound after years of declining commodity prices.

Hitachi Construction Machinery plans to start a tender offer for Bradken for six weeks from mid to late-October, according to its statement. The Australian company last year rejected a A$428-million offer from Koch Industries andPacific Equity Partners, saying it didn’t reflect the fair value.

The Japanese company will use funds on hand as well asbank borrowing to finance the acquisition, it said. The company is Japan’s second-biggest maker of constructionand mining equipment, while it has the biggest global share of giant excavators used in mining.

The plan was announced after the Japanese stock market closed on Monday. Hitachi Construction Machinery, half owned by Hitachi, closed 0.6% higher at 2 011 yen in Tokyo, extending its gain this year to 6%.

DTE unveils plans to spend up to $1.5 billion on gas plant construction

DTE Energy expects to formally notify Michigan regulators in October that it plans to build the first of what could be several natural gas-fired power plants as part of an ambitious strategy by the state's largest electric utility to invest up to $1.5 billion to replace a portion of the coal generation it intends to retire by 2023.

A full-scale application for a certificate of need for the initial project will be filed with the Michigan Public Service Commission in mid-2017, DTE spokesman Brian Corbett said Friday in an interview.

The Detroit-based company has indicated for months it will rely on natural gas and renewables to replace the St. Clair, River Rouge and Trenton baseload coal-fired plants that will be shut over the next six years. Now, it is revealing specifics.

One of the first new gas-fired plants the utility will build is likely to be located on existing DTE property adjacent to the 1,395 MW Belle River coal-fired plant in St. Clair County, Michigan, DTE spokesman Brian Corbett said in a Friday interview.

In all, DTE plans to install about 1,000 MW of energy next decade, although it remains unclear how many gas plants will be built. "We're talking about at least one new gas plant, probably more," Corbett said.

The first gas-fired plant is targeted for commercial operation in the 2021-2023 time frame.

DTE Chairman and CEO Gerry Anderson said in a statement his company is "committed to providing Michigan and our customers with reliable, cleaner sources of energy. These new energy generation investments will significantly reduce greenhouse gases by moving to cleaner technologies. Just as important, it enables us to deliver safe, affordable and reliable energy for DTE's 2.2 million customers."

DTE and Spectra Energy are co-developers of the proposed 255-mile Nexus natural gas pipeline that would carry 1.5 Bcf/d the Marcellus and Utica shale fields to Michigan and Ontario, Canada.

In September, the companies received an air permit for the $2 billion project. They next need to secure a final environmental impact statement from the Federal Energy Regulatory Commission. If everything goes as planned, construction could start in late 2017, with completion before 2020.

DTE has about 12,000 MW of generation, including 6,300 MW coal, 2,700 MW natural gas, 1,100 MW nuclear, 950 MW pumped storage hydro and 930 MW renewables. Until this year, DTE had retired only about 200 MW of older coal generation, but after its June retirement announcement for St. Clair, River Rouge and Trenton, DTE has only two remaining coal plants -- Belle River and 3,000 MW Monroe -- that it has not yet planned to retire.

If the first gas-fired plant is built at Belle River, it suggests that the coal-fired plant probably will be closed sometime next decade as well, although Corbett would not confirm such a scenario.

"Right now," the company has said that Belle River and Monroe will operate "beyond 2023," he said.

Indeed, it appears likely that Monroe, on the western shore of Lake Erie and one of the biggest power plants in the Midwest, may be DTE's only coal-fired plant to continue operating past 2030.

Attached Files

Colombia's Santos, FARC scramble to revive peace after shock vote

Colombia's government and Marxist FARC guerrillas will scramble on Monday to revive a plan to end their 52-year war after voters rejected the hard-negotiated deal as too lenient on the rebels in a shock result that plunged the nation into uncertainty.

Putting on a brave face after a major political defeat, President Juan Manuel Santos offered hope to those who backed his four-year peace negotiation with the Revolutionary Armed Forces of Colombia (FARC) in Cuba.

Latin America's longest conflict has killed 220,000 people.

"I will not give up, I will keep seeking peace until the last minute of my term," he said moments after losing Sunday's plebiscite to those who want a re-negotiation of the deal or an obliteration of the FARC on the battlefield.

Santos plans to meet all political parties on Monday and send lead government peace negotiator Humberto de la Calle back to Havana to speak to the FARC leadership.

Rodrigo Londono, the top FARC commander better known by his nom de guerre Timochenko, also offered reassurance the rebels remain committed to becoming a peaceful political party.

"The FARC reiterates its disposition to use only words as a weapon to build toward the future," Timochenko said after the result. "Count on us, peace will triumph."

Santos, 65, who was not obliged by law to hold a plebiscite, had said there was no Plan B for the failure of the peace vote, but now appears ready to consider options.

Colombians, even those who backed the "No" vote, expressed shock at the outcome and uncertainty about the future.

"We never thought this could happen," said sociologist and "No" voter Mabel Castano, 37. "Now I just hope the government, the opposition and the FARC come up with something intelligent that includes us all."

The peace accord reached last month and signed a week ago offered the possibility that rebel fighters would hand in their weapons to the United Nations, confess their crimes and form a political party rooted in their Marxist ideology.

SIXTIES ROOTS

The FARC, which began as a peasant revolt in 1964, would have been able to compete in the 2018 presidential and legislative elections and have 10 unelected congressional seats guaranteed through 2026.

That enraged "No" supporters, including powerful former president Alvaro Uribe, who argued the rebels should serve jail terms and never be permitted to enter politics.

Uribe, a onetime ally who has become Santos' fiercest critic, may now hold the key to any potential re-negotiation.

While the FARC has refused to serve traditional jail terms, it may see no future in returning to the battlefields and so consider some sort of new deal.

"In the end, the people have spoken: the Colombian government and the FARC have no choice but to renegotiate," said Peter Schechter, director of the Adrienne Arsht Latin America Center.

The FARC already softened its stance in the original negotiation, publicly admitting for the first time it trafficked drugs, recruited minors and committed human rights violations, including massacres.

But voters worried the rebels would fail to turn over assets from drugs and illegal mining, potentially giving them a formidable war chest that could outstrip the coffers of traditional parties.

Regions still riven by the conflict, including poor areas along the Pacific and Caribbean coasts, voted resoundingly in favor of the deal, but formerly violent interior areas pacified during the Uribe presidency largely backed the "no" camp.

"How sad. It seems Colombia has forgotten about the cruelty of war, our deaths, our injured, our mutilated, our victims and the suffering we've all lived through with this war," said Adriana Rivera, 43, a philosophy professor standing tearfully at the hotel of the "yes" campaign.

The vote may delay Santos' plans to move on to other matters including much-needed tax reform and other macroeconomic measures to offset a drop in oil income. It will also dent his hopes for a boom in foreign investment in mining, oil and agriculture in Latin America's fourth-largest economy.

Germany says watching Chinese takeover interest closely

The German government is carefully watching the interest of Chinese businesses in taking over companies in Germany, an Economy Ministry spokeswoman said on Friday.

The spokeswoman declined to comment on a report in German business daily Handelsblatt that potential buyers of shares in lighting group Osram had been in contact with Siemens , which holds a stake in Osram.

But she added: "We are carefully watching the overall situation, especially concerning takeovers from China."

Oil and Gas

Exxon Is Hit With Fine From Chad Five Times Country’s GDP

Exxon Mobil Corp. was ordered to pay a record $74 billion fine in Chad for underpaying royalties in the central African nation where the company has been drilling for 15 years, according to a court document.

The fine is about five times more than Chad’s gross domestic product, which the World Bank estimates at $13 billion. The High Court in the capital, N’Djamena, announced its ruling Oct. 5 in response to a complaint from the Finance Ministry that a consortium led by Exxon hadn’t met its tax obligations. The court also demanded the Texas-based oil explorer pay $819 million in overdue royalties, according to the document.

The penalty exceeds the $61.6 billion financial blow BP Plc incurred after the Deepwater Horizon disaster in 2010 killed 11 rig workers and fouled the Gulf of Mexico with crude for months, and is more than 70 times larger than the $977.5 million Exxon was ordered to pay fishermen and other victims of the 1989 Valdez oil spill in Alaska. Chad is unlikely to collect most of the fine, said Jeffery Atik, who teaches international law at Loyola Law School in Los Angeles.

“Nobody is going to cooperate outside of Chad in enforcing this judgment,” Atik said in a telephone interview. “This leaves Exxon exposed to possibly losing everything it has inside Chad but that’s such an extraordinary number, I can’t imagine the assets they have there are worth that much.”

Marine Terminal

Exxon, the world’s biggest oil producer by market value, began exploring Chad for crude in 2001 and has been pumping oil there since 2003. The company also operates a pipeline that hauls Chadian oil to a marine terminal in Cameroon for export. The two other companies named in the case are Chevron Corp. and Malaysia’s state-owned Petroliam Nasional Bhd. Chevron sold its stake in Chad in 2014 and spokeswoman Isabel Ordonez declined to comment.

“We disagree with the Chadian court’s ruling and are evaluating next steps,” Exxon spokesman Todd Spitler said by e-mail Thursday. “This dispute relates to disagreement over commitments made by the government to the consortium, not the government’s ability to impose taxes,” he said in a later e-mail, declining to comment on the $74 billion figure.

The president of the court, Brahim Abbo Abakar, confirmed the ruling by phone on Thursday.

“It’s correct, however, the provisional enforcement is lower than the amount demanded by the tribunal,” he said, referring to the sum of $669 million also cited in the document. He didn’t elaborate.

Chad’s Finance Minister Ngabo Seli Mbogo said the court ruling was clear and he didn’t want to comment further.

“It’s not a realistic thing and it will never be collected,” said Robert Amsterdam, a lawyer at Amsterdam & Partners LLP who has represented international corporations and sovereign governments. “This is much more about signaling that a renegotiation is in order than something that should trouble shareholders in any way.”

BP to set up fuel stations in India, challenge state firms' dominance

Global oil major BP plans to open up to 3,500 fuel stations in India, becoming the second overseas firm drawn to rising demand for gasoil and gasoline in the world's fastest growing major economy.

BP will join European oil major RoyalDutch Shell as the only foreign firms selling fuel in the country, challenging the market share of state refiners that control 93 percent of India's more than 56,000 outlets.

An oil ministry official told Reuters BP would be issued permission to set up the stations by Monday. A BP India spokeswoman confirmed the company had applied for a license to set up the fuel stations.

India is replacing China as the driver of global oil demand growth as its economy expands and a rising middle class buys motor vehicles. The International Energy Agency expects India to account for a quarter of global energy use by 2040.

"There is space for everybody as our fuel demand is growing," said M.K. Surana, chairman of state-owned Hindustan Petroleum Corp, adding that the entry of new players will make the retail market more competitive.

"State refiners will have to adopt novel ways to boost sales and retain their market share," added Surana, whose firm signed a deal this week to sell milk products at its retail outlets to attract customers.

India ended control over gasoline prices in 2010 and on diesel in 2014, making retail fuel attractive for private players like Essar Oil and Reliance Industries which are expanding their retail presence.

BP pulled out of a refinery and marketing joint venture with HPCL in 2006, when retail prices were way below market rates and federal financial support was given only to state firms.

"It is highly unlikely that India will revert to the subsidies regime, more so because of low oil prices. This strengthens the confidence of new players to enter the Indian fuel market," said Tushar Tarun Bansal, director at Singapore based consultancy Ivy Global.

Oil minister Dharmendra Pradhan said in June that global oil majors including Saudi Aramco and Total planned to tap the retail fuel market in India.

Indian fuel markets could be a lucrative prize for BP, which reported a 45 percent drop in second-quarter earnings. It has also received an Indian licence for jet fuel sales.

It is not clear where BP will source fuels for local sales. India's pricing formula gives higher profits to retailers with refining plants or domestic supply sources.

"BP already has a tie up with Reliance on the gas side so there is a possibility they may strengthen this relationship further to the downstream side of the business," said Bansal.

BP in 2011 acquired a 30 percent stake from Reliance in some exploration blocks and formed a gas sourcing and marketing tie-up with the Indian conglomerate. Reliance operates the world's biggest refining complex in western India, but controls only a small share of retail fuel markets.

"Any refining or product sale tie-up with BP will suit Reliance which recently decided to exit from the African market, leaving it to explore new geographies and clients for its fuel," Bansal said.

Oil curves move above $50 as financial confidence in crude rises

U.S. oil futures held above $50 per barrel on Friday as the entire crude forward curve pushed above above that level in a sign that financial markets have increasing confidence in the sector.

U.S. West Texas Intermediate (WTI) futures CLc1 settled at $50.44 per barrel on Thursday - the first settlement above $50 since June 24 - and were up 6 cents on Friday at $50.50 per barrel at 0542 GMT.

Brent futures LCOc1 already moved over $50 at the start of this week, and were trading at $52.57 per barrel at 0542 GMT on Friday, also up 6 cents.

With both front-month contracts above $50 per barrel and each forward curve in contango, in which contracts for future delivery are more expensive than those for immediate sale, the entire crude futures complex has moved back over $50 per barrel.

"There is still no end in sight for the current bullish run. Speculators have been buying every short-term dip, a strategy that has evidently been working very well so far," said Fawad Razaqzada, market analyst at futures brokerage Forex.com.

"This trend could well continue for some yet as after all crude oil's fundamental outlook continues to improve: as well as the planned OPEC oil output cut, we have seen surprise inventory destocking in the U.S. for five straight weeks now. Consequently, U.S. oil stocks have now fallen below 500 million barrels for the first time since January," he added.

The Organization of the Petroleum Exporting Countries (OPEC) plans to agree on a coordinated production cut when it next meets in late November, in a bid to rein in a global fuel supply overhang that has dogged prices for the last two years.

"OPEC kept the heat on oil prices overnight. The Algerian Energy Minister saying that OPEC could cut by more than the 0.5 million barrels per day initial agreement," said Jeffrey Halley of brokerage OANDA.

"More significantly representatives of both OPEC and Non-OPEC producers will meet for a tete-a-tete on the sidelines of yet another energy conference next week."

In a sign of ongoing oversupply, top exporter Saudi Arabia cut its benchmark crude prices to Asia this week, and analysts at JBC Energy warned there was "a growing disconnect between the physical and the financial (oil) market" which would likely converge.

HSBC on Friday said recent gains in Brent and WTI should be kept in perspective, cautioning that seasonal aspects of the price rally would fade again soon.

Tokyo Gas considers swapping LNG cargoes

Tokyo Gas of Japan could swap its United States LNG volumes with equivalent quantities of Asian sourced liquefied natural gas.

Michiaki Hirose, Tokyo Gas president said the company would deliver its US sourced LNG to a number of locations while bringing Asian sourced LNG to Japan, Platts reports.

The company has booked 0.72 million tons of LNG per year from the Cameron LNG project and an additional 1.4 million tons of LNG per year from the proposed Cove Point LNG terminal.

Hirose was reported as saying that swapping cargoes could provide resistance to price movements resulting in cheaper LNG cargoes. He added that the company could consider forming alliances for LNG business.

A number of Japanese companies have already made arrangements to deliver USA LNG to other destinations.

Kansai Electric and Engie agreed to cooperate on LNG procurement. Engie agreed to buy 0.4 million tons per annum of LNG from Kansai’s North American LNG. Depending on markets conditions, Engie could then sell an equivalent amount of LNG to Kansai Electric in Japan.

The transaction will start in 2019 for an initial period of four years which can be extended up to 20 years.

Earlier this year, Jera, a joint venture between Chubu Electric and Tepco, agreed to sell about 1.5 million mt to EDF Trading at European LNG terminals for a period of approximately two and a half years beginning in June 2018. The volumes will be sourced from the Freeport LNG project in the United States.

Oil company dealt another blow on plan to ship crude by train

For the second time in a month, a California community has rejected an oil company’s plans to ship crude oil on long trains through Sacramento and other cities to coastal refineries.

The San Luis Obispo County Planning Commission on Wednesday voted to reject a request by Phillips 66 Co. to build a facility at its Nipomo Mesa refinery that would allow it to receive oil shipments via three trains a week, some of which likely would have traveled through Sacramento and other Northern California communities.

The 3-2 vote to deny Phillips can be appealed by the company to the county Board of Supervisors.

Two weeks ago, the City Council in Benicia unanimously rejected a proposal by Valero Refining Co. that would have allowed it to receive oil from two 50-car trains daily on rail lines through downtown Sacramento, Roseville, West Sacramento, Davis, Dixon and other Northern California communities, as well as through the Feather River Canyon watershed.

Both oil companies were seeking local approval to build spur rail lines and oil transfer stations at their refineries to access oil from North American crude-oil fields, which have seen a boom from new hydraulic fracturing – or fracking – technology.

The requests pitted the oil companies against anti-oil activists, environmentalists and leaders of communities along rail lines, including officials in Sacramento and Davis who said they were concerned about the potential for catastrophic derailment and fires involving the volatile liquid.

The increase in crude-oil train shipments nationally has led to more derailments and explosions over the last half-dozen years. The worst of those accidents killed 47 people in a Canadian town three years ago. Although oil trains have become common in many areas, large oil shipments on rail remain rare in California, due in part to opposition. Several 100-car trains of volatile oil from the Bakken region of North Dakota traveled through midtown Sacramento in 2014 to the Bay Area, but those shipments stopped late that year.

Local leaders cheered the decisions by Benicia and San Luis Obispo to reject the plans. Yolo County Supervisor Don Saylor said the Benicia council decision, in particular, sends a message nationally that local communities can have a say over whether or not mile-long oil trains will travel through their communities.

“The community of Benicia, in the crosshairs of history, made one of those decisions that will make a difference for the country. They stood up and said the safety of our communities matters,” Saylor said.

In a letter this week, a Valero oil company attorney contended the city of Benicia acted illegally when it rejected Valero’s plan to ship two 50-car oil trains a day through Northern California to the company’s Benicia refinery. Benicia officials, however, said they believe their decision is legally solid.

Valero officials have suggested in the past they might sue the city. Valero spokesman Chris Howe in an email this week to The Sacramento Bee said the company “continues to consider all of its options.”

Libya's Zueitina loads first crude export cargo since 2015

A tanker on Thursday loaded the first crude export cargo at Libya's Zueitina oil terminal since late last year, a port official said.

Zueitina is one of three previously blockaded ports in Libya's oil crescent region that reopened last month after forces loyal to eastern commander Khalifa Haftar took control of the terminals.

The port official said the Ionic Anassa was loading 800,000 barrels of oil for export to China.

The reopening of Zueitina, Ras Lanuf and Es Sider has helped boost Libya's oil production, which had been slashed to a fraction of the 1.6 million barrels per day (bpd) that the OPEC member was producing before its 2011 uprising.

Zueitina had been shut since early November 2015, and Ras Lanuf and Es Sider since December 2014. Exports have already resumed at Ras Lanuf but are yet to restart at Es Sider, which was badly damaged in fighting.

A Libyan oil official said national production stood between 505,000 bpd and 510,000 bpd on Thursday, just up on levels recorded at the start of the week. Before the ports changed hands on Sept. 11-12, Libya's output had been hovering between 200,000 and 300,000 bpd.

Haftar's forces have pledged to leave the ports in control of the National Oil Corporation (NOC) in Tripoli.

The NOC has said it hopes to raise production to as much as 900,000 bpd by the end of the year, but that reaching this target depends on funding for operating costs and the reopening of blockaded pipelines in western Libya.

Will Russia's 'staggering' hike in oil production dampen recovery?

Russia's output has raised concerns that non-OPEC producers will offset any cuts by the cartel.﻿

Russia is smashing post-Soviet oil records, producing more crude in September than it has in decades and raising questions of whether promised output cuts by OPEC would succeed in reducing the worldwide oil glut.

Russia produced 11 million barrels per day in September, a 200,000-barrel or 2 percent jump over its previous post-Soviet record, set in January, and a 400,000-barrel or 4 percent increase on the year, the country's energy ministry reported. Analysts at Tudor Pickering Holt pegged the rise to a weak ruble, meaning Russia, which depends heavily on oil to support its economy and finance its government, has to pump more oil to generate the same amount of revenues.

The Organization of the Petroleum Exporting Countries last month reached a preliminary agreement to cut production by up to 750,000 barrels a day, with plans to formalize the reduction at OPEC's formal meeting in Vienna in November. That agreement has helped push oil prices toward $50 a barrel again. Also supporting prices has been a steady drop of petroleum stockpiles in the United States.

The Energy Department reported Wednesday that commercial crude inventories fell by about 3 million barrels, the fifth consecutive week of declines amid strong energy demand. Crude settled at $49.83 a barrel, the highest close more than three months.

Russia's record production, however, has raised concerns that non-OPEC producers will offset any reductions in output by the cartel. U.S. shale drillers, for example, have put scores of rigs back to work as prices have come off their February low of $26 a barrel and hovered between $40 and $50 a barrel in recent months.

Russia has at times promised to cut production and aligned itself with OPEC to reduce supply and drive up oil prices. If so, it didn't last month.

The rise was driven in part by an 8 percent bump in production on the North Pacific island of Sakhalin, analysts said. State-owned oil companies Rosneft and GazpromNeft, plus the private giant Lukoil, contributed the largest increases.

Still, analysts aren't convinced the Russian production spike will last. Piper Jaffray said September figures were, in fact, a few thousand barrels lower than the International Energy Agency expected. Tudor Pickering said Russian Energy Minister Alexander Novak has discussed freezing production just under 11 million barrels per day. And Rosneft and Lukoil have predicted their volumes would decline in the second half of this year due to financial constraints.

Tanzania Plans to Commission Natural Gas Plant by 2025

Tanzania, which has at least 57 trillion cubic feet of natural gas reserves, plans to commission a plant by 2025 to process as much as 11.1 trillion cubic feet.

The Ministry of Energy’s plan estimates that the East African nation can recover as much as 70 percent of the resource. It also projects total demand at 32.5 trillion cubic feet over three decades, with 8.8 trillion cubic feet going to power generation, according to a document handed to reporters in the commercial capital, Dar es Salaam.

Tanzania utilizes about 33 billion cubic feet each year to generate 711 megawatts of electricity, according to the document. The nation plans to export at least 3.1 trillion cubic feet of natural gas to East and Southern Africa in the 30 years through 2045 as global prices drop.

“Declining global prices mean regional markets maybe be a better option to monetize the resource,” according to the plan.

Global production of natural gas is forecast to grow 7.6 percent each year to reach 500 million tons per year in 2030, according to the International Gas Union.

“Tanzania should not necessarily start allocating gas ratios as that might encourage the growth of unsustainable industries,” Paul Hogarth, an upstream commercial team leader at London-based BG Group said at a conference in Dar es Salaam Wednesday.

Colder temperatures this winter are likely to drive up residential and commercial demand for natural gas and provide support for wholesale prices, compared with 16-year lows seen last winter, the Natural Gas Supply Association said in its winter outlook released Wednesday.

NGSA projects overall demand will rise 3.2 Bcf/d, or 3.6%, to a record average of 92.3 Bcf/d in the coming season as a winter that is forecast to be 12% colder than the year-ago period boosts demand from the residential and commercial sectors by a combined 4 Bcf/d, the group said in its winter 2016-17 outlook.

The trade association's outlook evaluates impact of weather, economic growth, customer demand, storage inventories and supply on prices. It expects support from weather and overall demand, while seeing a "neutral" impact from the economy, storage and winter supply.

The projection is based on published data from independent and government sources including the US Energy Information Administration and National Oceanic and Atmospheric Administration. NGSA used to Energy Ventures Analysis and EIA data for its demand and supply projections, and IHS Economics data for its economic projections.

The projected demand increase in the outlook is tempered by a decline in power sector consumption, as the expected rise in gas prices will lead to reduced coal-to-gas switching.

"NGSA anticipates temporary fuel switching to natural gas to continue this winter, but at about half the volumes that took place during last winter's record-setting fuel switching," said Bill Green, chairman of NGSA and vice president, downstream marketing for Devon Energy, in a statement.

EVA projected the decline in the power sector demand to be 3.3 Bcf/d, or 13%.

Residential demand is "the biggest change from last year," Green said in a briefing for reporters. The outlook projected residential demand will grow by 12% compared with last winter's levels.

The EVA data underpinning the outlook puts average residential demand for the season at 22.8 Bcf/d, up 2.8 Bcf/d from last winter. It also points to a 2.4% rise in industrial demand to 22.9 Bcf/d, driven by new facilities coming online, including capacity expansions in the gas-intensive petrochemical and fertilizer industries.

Weather remains a major wildcard, according to Green, who said last year's outlook "failed miserably," because of what proved to be the second-warmest winter on record, with the average price at $1.98/MMBtu at Henry Hub, he said. This year's forecast of colder weather is still 3% warmer than the 30-year average, he noted.

"If it got 20% colder than normal I still think that with storage and all the production we have, we'll be fine," he said. There could still be some regional issues such as capacity constraints in the Northeast, he added, but the prices spikes seen in the past are less likely, he said.

Overall, Green said the market is well positioned, with robust production, full storage and new infrastructure adding flexibility.

"Somebody might say [prices will be] 50% higher. At $3 it's still an excellent price for generators and residential customers," he said.

The EVA report said that based on recent NYMEX futures prices, gas prices for the winter are expected to be 50% higher than they were last year.

On the storage and supply front, the NGSA outlook projected a small decrease in production of 0.5 Bcf/d, and a potential for record inventory of gas in storage.

Exports to Mexico are projected to grow 800 MMcf/d, Green said, adding the group expects that number to rise going forward as new infrastructure is built to carry gas to Mexico.

The response of US shale production over the next two months may well impact how OPEC decides to finalize the tentative production freeze it announced last week in Algiers, the head of the US Energy Information Administration says.

"Shale has dramatically changed the kind of strategy that OPEC was employing," Adam Sieminski told S&P Global Platts on Wednesday.

"OPEC will be looking at our production statistics and if they saw US production beginning to recover, would make difference to what they were doing," Sieminski said an energy seminar at Japan's Institute of Energy Economics.

Amid recovering oil prices, Sieminski said "there is still financing available in the US oil drilling activities and upstream investments."

Sieminski's comments came after OPEC agreed on a blueprint for its first production cut in eight years at an extraordinary meeting in Algiers on September 28.

OPEC ministers agreed to cut production to between 32.5 million b/d and 33 million b/d. The deal would mean a total cut of 200,000-700,000 b/d, when compared with OPEC's 33.2 million b/d August production, based on OPEC secondary sources.

Final details of the freeze -- including individual country allocations and which production estimates are used to verify compliance--are to be decided by OPEC's next formal meeting, November 30 in Vienna.

OPEC has also said it will seek support for the cut from non-OPEC producers.

Sieminski, who served as chief energy economist at Deutsche Bank for almost seven years before being named EIA administrator in 2012, said the OPEC deal appears aimed at putting a floor under oil prices.

CAPEX CONCERNS

But Sieminski added: "We would have to know how effective those cuts going to be," referring to uncertainties over production levels in Libya, Nigeria and Venezuela, which have been racked by domestic turmoil.

While EIA is maintaining its view on the timing of rebalancing oil markets towards the end of this year and into the middle of 2017, Sieminski said, "If OPEC is successful in reducing production, it might cause that happen sooner."

But OPEC would need to be careful about its production cut because it could not only send oil prices but also US shale oil production higher, he added.

US production has proved resilient even without higher prices as the EIA has revised higher its US production forecast for 2017 due to increased drilling activity, rig efficiency and well-level productivity.

EIA forecast 2017 production would be 8.5 million b/d per its latest Short-Term Energy Outlook in September, which was 200,000 b/d higher than its August forecast for next year.

"EIA's long term projection says oil price will likely to go up so if OPEC cuts too much production, the prices are going to go high," Sieminski said. "We are going to have more oil production in shale in the US, [which would result in] the less demand so it's a self-correcting mechanism."

He reiterated a long-standing concern that he and many other market watchers have had as the oil price slump has persisted: Will the industry's drastic cuts in capital investments make it unable to support mid-term global oil demand growth?

EIA analysis has suggested that sustained prices below $50/B may not be enough to sustain enough supply, with the global economy starting to pick up.

"EIA's view is that there [will be] big growth in global oil demand unless we have some kind of global recession, which we are not forecasting," he said.

"To me an interesting question is goes beyond some of these short-term questions about OPEC's cut in oil production activities in the near term more towards: 'Are we going to have enough capital investment in oil area to provide for likelihood of demand for petroleum continues to grow globally over the next five to 10 years because of growth in economy?'"

Undaunted by Gas Price Cut, ONGC Firm on $4.5 Billion Capex

India’s largest oil and gas producer will continue with its record investment plan despite a cut in domestic gas prices, which were reduced for the fourth consecutive time last week.

Oil and Natural Gas Corp. plans to invest about 300 billion rupees ($4.5 billion) in the year beginning April 1, including investment in its gas-rich Krishna-Godavari block off India’s east coast, ONGC’s Director for Finance A.K. Srinivasan said in a phone interview. It will spend as much as 293 billion rupees this financial year as part of its plan to boost oil and gas production.

“Gas prices are cyclic. Capex will continue,” Srinivasan said, adding that the company’s profit falls by about 24 billion rupees for every $1 cut in the gas price. “You can’t produce for one year and choke up and then continue again.”

The company has previously said it plans to invest $5 billion in its block in the Krishna-Godavari Basin. Its plans to spend 11 trillion rupees by 2030 to raise output is key to Prime Minister Narendra Modi’s target of cutting import dependence by 10 percent in the next six years. India, which imports most of its oil, will be the fastest-growing crude consumer in the world through 2040, according to the International Energy Agency.

On Friday, India cut the price of locally-produced natural gas by 18 percent for the six months beginning Oct. 1 to $2.5 per million British thermal units based on its gross heat value. It also reduced the ceiling price for natural gas extracted from difficult fields by 20 percent to $5.3 per million Btu.

“At such low gas prices, the upstream producers will be hit the most as gas production will turn loss making for most fields,” K. Ravichandran, senior vice president for corporate ratings at Mumbai-based credit assessor ICRA Ltd., said in a note on Monday.

ONGC’s shares rose 0.9 percent to 269.15 rupees at the close in Mumbai.

Attached Files

OPEC could cut output more in Nov if needed: Algeria

OPEC could cut production at its late November meeting in Vienna by another one percent more than the amount agreed in Algiers last month, if producers reckon it is needed, Algeria's Energy Minister Nouredine Bouterfa has told local Ennahar TV.

He also told Ennahar that OPEC and non-OPEC members would hold an informal meeting in Istanbul Oct. 8-13 to discuss how to implement the Algiers deal, though he did not give details about who would attend.

OPEC producers agreed in Algiers in September to reduce output by around 700,000 barrels per day to a range of 32.5-33.0 million barrels per day, its first cut since 2008. OPEC estimates its current output at 33.24 million bpd.

"We will evaluate the market in Vienna by the end of November and if 700,000 barrels are not enough, we will go up. Now that OPEC is unified and speaks in one voice everything is much easier and if we need to cut by 1 percent, we will cut by 1 percent," Bouterfa told Ennahar in an interview to be broadcast later on Thursday.

Algeria is one of OPEC's price hawks and this was the first suggestion of a possible further decrease in output. Before the Algiers meeting Bouterfa had been pressing for a one million bpd OPEC production cut to stabilize prices.

Russia's Rosneft to pay up to $5.3 billion for Bashneft stake: Ifax

Russian oil producer Rosneft may pay up to 330 billion roubles ($5.29 billion) for a controlling stake in mid-sized oil company Bashneft, Interfax news agency cited two sources familiar with the planned deal as saying on Thursday.

The deal to buy a stake of just over 50 percent in Bashneft, and all other accompanying agreements, are to be signed by Oct. 15, the agency reported.

Chief exec of Norway Oil Industry Association warns over oil revenues

The chief executive of the Norwegian Oil Industry Association has warned access to new area of exploration is essential in order to boost revenue in the Scandinavian country.

Karl Eirik Schjoot-Pedersen made the comments after the government put estimated of oil revenue in the state budget at NOK138billion.

The boss of the Association said the decrease any imbalance between revenue from petroleum industry and spending should be taken seriously.

He said revenue from the sector was essential in order to maintain and further develop the Norwegian Continental Shelf (NCS).

Schjoot-Pedersen added flagging revenue, regardless of the oil price, would mean in years to come there would be less income from the industry as a number of fields also come towards the end of their life.

In 2014, revenue from the industry was NOK312billion and oil spending was NOK156billion.

In the budget for next year, revenues are estimated at NOK138billion.

Schjott-Pedersen also warned declining revenue could lead to a rise in taxes adding it showed “how important” it was to maintain large revenues from oil and gas operations.

FERC updates on Plaquemines LNG project

The US Federal Energy Regulatory Commission (FERC) has released an update on its pre-filing environmental review of Venture Global Plaquemines LNG’s application to construct an LNG export terminal and the Gator Express Pipeline interconnected pipeline.

FERC states that it is continuing to conduct its review of the planned project based on the information that it has have received from Plaquemines LNG and Gator Express Pipelin, as well as the comments that it has received from stakeholders. FERC received one set of draft Resource Reports (RRs) from Plaquemines LNG and Gator Express Pipeline Project and provided its comments in February 2016. The companies provided revised draft RRs in August 2016 and FERC is currently reviewing these to provide its comments to Plaquemines LNG and Gator Express Pipeline.

After Plaquemines LNG and Gator Express Pipeline file their formal application, FERC will issue a Notice of Application and identify the CP Docket number for the project. This Notice of Application will outline how interested parties can become intervenors and how persons can continue to comment on the project.

When FERC has all of the information necessary to complete its analysis and write the Environmental Impact Statement (EIS), it will issue a Notice of Schedule for Environmental Review that will identify the date for issuing the EIS.

Venture Global Plaquemines LNG LLC plans to construct and operate an LNG terminal on the west bank of the Mississippi River in Plaquemines Parish, Louisiana, US. Venture Global Gator Express LLC (Gator Express Pipeline) plans to construct and operate two natural gas supply pipelines that would connect the LNG terminal to the existing interstate natural gas grid. The two pipelines would be mostly parallel and adjacent to one another. These co-located pipelines are identified as Southwest Lateral Texas Eastern Transmission LP (TETCO) and Southwest Lateral Tennessee Gas Pipeline LLC (TGP). Each of these pipelines would have a nominal gas supply capability of 1.97 standard billion ft3/yr of natural gas.

BHP Billiton hits pay in Caicos well

BHP Billiton has announced positive drilling results at the Caicos exploration well in the Gulf of Mexico.

Located in Green Canyon 564 where BHP Billiton has 100% interest, this well is approximately 100 miles south of the Louisiana coast in the deepwater Gulf of Mexico.

The company said on Wednesday that Caicos was drilled to a total depth of 30,803 feet and encountered oil in multiple horizons. The well was drilled with Seadrill’s 2013-built drillship West Auriga.

The 6th generation ultra-deepwater drillship West Auriga is under a long-term contract with BP in the Gulf of Mexico. The rig’s contract was assigned to BHP Billiton Petroleum (Deepwater) Inc., on June 10, 2016, for one well with an option for a second well with BP’s consent.

BHP Billiton President Operations Petroleum, Steve Pastor, said at an investor briefing in London:“We are encouraged by the Caicos results and are moving to further appraise the area. The next step will be drilling the Wildling well in November. With success at Caicos and Shenzi North, we continue to be optimistic around the opportunity for a commercial development in the area.”

Earlier this year, BHP Billiton announced plans to increase its spending on exploration for the next year. The company plans to invest approximately $900 million dollars in exploration, which represents 18 percent of its overall capital budget.

He reminded of the incident on July 26, when “some LNG was sent by mistake into the BOG circuits and a small amount flowed as far as the base of the flare, causing a fire.”

He added that the incident was due to a malfunction of level sensors.

Additionally, following the incident, the high-pressure BOG compressor, the equipment that makes it possible to send extra gas across the network, was started and the flare, which was working until August 12, is now extinguished.

The next step TS LNG is set to take is to send gas through the network under normal working conditions.

Brazil Opens Oil Fields to Foreign Firms in Major Policy Shift

Brazil’s Congress voted on Wednesday night to open up its pre-salt oil fields to foreign investors by scrapping Petroleo Brasileiro SA’s obligation to be the area’s sole operator.

The legislation was approved by a 292-to-101 vote, following a bad-tempered debate during which opponents, many dressed in the orange jumpsuits of the state-controlled oil company, repeatedly attempted to delay proceedings. Various amendments to the legislation will be debated next week before President Michel Temer signs it into law.

In a significant change to Brazil’s offshore oil industry regulations, companies other than Petrobras can now operate blocks in the largest deep-water deposits discovered this century. Until now the heavily indebted state-controlled oil producer was legally obliged to operate all the pre-salt fields with a 30 percent minimum stake.

Legislation to open up the area to foreign investors began under former President Dilma Rousseff, but many within her left-wing Workers’ Party were deeply hostile to the idea. Tuesday’s vote, backed by the Petrobras leadership, marks the most investor-friendly change in regulation since the 1997 oil law that ended the state company’s monopoly in Brazil.

"It’s a very important sign that the government is in control of this process to open up the industry," said Milton Costa, the secretary-general for the Brazilian Petroleum Institute, or IBP, an oil industry lobbying group. "There’s no way Petrobras can handle the pre-salt requirements by itself."

First Pick

Petrobras will have the first pick of the fields in the area, according to the new regulation. Since he took over the running of the company on June 2, Petrobras CEO Pedro Parente has repeatedly warned that its obligation to participate in all investments would delay pre-salt exploration due to financial constraints. The old rule also limited the company’s freedom to participate only in fields of its choice, according to Parente.

The congressional vote eases nationalistic oil policies that have been in place since 2007, the year Brazil announced it had discovered the largest group of offshore deposits this century in a region where the oil is trapped under a layer of salt, miles below the seabed.

After the discovery, Brazil suspended all bidding rounds while Congress discussed new regulation designed specifically for the pre-salt region. The law passed in 2010 and in 2013 established the rules for oil auctions. But since then, Petrobras has cut investments by more than a half and lower oil prices have reduced the profitability of the highly costly deep-water fields.

‘Handing Over’

No companies competed against a Petrobras-led consortium at the first and only auction of the deep-water blocks. Nevertheless, opposition to foreign ownership of Brazilian natural assets remains an article of faith for many on the left.

"We are handing over on a platter control of an area that we discovered and over which we have jurisdiction to multinationals,"said Jandira Feghali, from the opposition Communist Party of Brazil.

The new regulations will attract investment as operators tend to set the development strategy and rhythm, according to IBP representative, Mauro Andrade. They also choose the technology applied in the fields.

The country still needs to clarify the rules governing field boundaries, local content requirement and whether to extend a tax incentive regime beyond 2020 for the oil industry to generate competition for the next bidding round, he said. Brazil expects to offer new pre-salt acreage as early as 2017.

"Brazil has taken an important step, but if the country doesn’t address these three issues there will be still uncertainty ahead," he said.

PIRA Energy expects oil surplus to be gone by second half of 2017

The surplus in crude oil supply that has led to a two-year price rout has been eroding since the second quarter and will be "gone" by the beginning of the second half of 2017, PIRA Energy Group founder Gary Ross told reporters on Wednesday.

A massive glut in oil brought crude prices crashing from the $100 a barrel range in mid-2014 to as low as about $27 early this year.

Organization of Petroleum Exporting Countries last week agreed to modest oil output cuts in the first such deal since 2008, limiting production to a range of 32.5 million-33.0 million barrels per day.

Global benchmark Brent crude prices have risen more than 10 percent in the week since the deal.

The decision by OPEC to embrace production cuts will help move crude prices toward a target of $50-$60 per barrel, said Ross, who is now chairman of the consultancy.

OPEC's policy has shifted as Saudi Arabia is targeting that price range and Iran has become more willing to accept an agreement, Ross said.

On Wednesday oil prices rose about 2 percent, touching their highest since June after an unexpected drop in U.S. crude stocks.[O/R]

Speaking at a news conference on the sidelines of PIRA's executive energy conference, Ross said that U.S. shale producers were likely to hedge more selectively after OPEC decided to limit output, whereas previously they looked to lock in future output close to the $50 a barrel level.

Shale producers and oil-consuming companies were under-hedged, he said, adding that industrial and airline buying would support prices.

On the upcoming U.S. presidential election, Ross said, if Democrat Hillary Clinton wins, the stock market will likely rally and raise the value of all risk assets, including oil and gas.

"People are going to be relieved that Trump is not there, because of his uncertain policies," Ross said.

Energy policy has come up only intermittently during the 2016 campaign.

This is the first time in 20 years that gasoline prices have not been a major topic of debate during a U.S. presidential election, said Jim Messina, campaign manager for President Barack Obama who also spoke at the news conference.

OPEC and non-OPEC oil producers plan an informal meeting in Istanbul Oct. 8-13 to discuss how to implement a production deal OPEC members reached in Algiers last month, Algerian Energy Minister Nouredine Bouterfa has told local Ennahar TV.

In an interview scheduled be broadcast on Thursday, Bouterfa said the Algiers deal to cut output would be in force for up to a year.

Oil prices rose about 7 percent in September, ending up a second straight month, after OPEC unveiled plans in Algiers to reduce output to between 32.5 million and 33.0 million barrels per day. Details are still being worked out among producers.

Chesapeake shores up capital with $1.25 billion debt deal

U.S. natural gas producer Chesapeake Energy Corp closed a private placement of $1.25 billion of debt on Wednesday, shoring up capital for debt repayment 10 months after it said it had no plans to file for bankruptcy.

Chesapeake, struggling with a huge pile of debt taken for shale development, said it could convert the 10-year notes to equity in three years if its stock trades above 130 percent of the conversion price for a specified period.

The company also said it exchanged its common shares for preferred shares representing about $1.2 billion of liquidation value, at a discount of over 40 percent.

Asia flows boost shipping rates, displace U.S. crude imports

Robust Asian demand for West African crude is fueling a worldwide surge in shipping rates for the largest oil tankers that is being felt from Houston to Singapore.

Chartering rates for Suezmaxes and very large crude carriers (VLCCs) have recovered rapidly in recent weeks after plunging to their lowest in more than year this summer.

The spike in rates comes as Asian refiners return to the market after a seasonal turnaround period, and as several key streams of West African crude are finally loading for export after supplies were constrained because of pipeline disruptions in Nigeria.

The higher rates, which imply fewer imports into the United States, could support benchmark oil prices in coming weeks.

Increased demand from Asia for this crude has tied up ships and barrels that might have otherwise moved to the United States. The higher prices are leaving brokers and traders scrambling to secure vessels, particularly for common routes from West Africa to the U.S. East Coast or Western Europe.

Chinese loadings of West African crude are set to average 1.1 million barrels per day in October, the highest since April.

The interest in Suezmaxes comes at a time when two key West African crudes, Nigeria's Qua Iboe and Forcados, return to the global market after a months-long force majeure. Rebels hit a sub-sea pipeline operated by SPDC, an affiliate of Royal Dutch Shell, in February, forcing the company to stop exports of the Forcados stream of oil.

Exxon stopped exporting Qua Iboe in July after a leak on the line feeding oil to the export terminal.

On Tuesday, Reuters tracking data showed that the first cargo since July of Qua Iboe loaded at a local terminal.

"Nigerian loadings are now scheduled to reach some 1.9 million barrels per day next month. The pick-up has had a clear effect on freight markets," JBC Energy said in note last week. Nigeria exported some 1.4 million bpd in September.

Transporting oil on larger vessels is more cost effective, especially for longer voyages.

In September, Suezmax volumes rose by nearly 60 percent from August, according to one ship broker, pushing the rates for the popular West Africa-to-United Kingdom route up to 110 percent of the World Scale, a shipping rate benchmark. In August, that route was as low as 35 percent, another broker said.

That rate has since leveled off this past week but remains elevated.

The spot rate for a Suezmax from the U.S. Gulf to Japan or South Korea is around $3.5 million, brokers say, more than double the rate for the same route two months ago.

Meanwhile, VLCC fixtures for October loading from West Africa are up 50 percent month-over-month, the first ship broker said. Last week, a VLCC moving from the Caribbean to Singapore was priced at about $3.85 million, up from $3 million just a week prior, a third broker said.

With higher rates, fewer imports could come into the U.S. East Coast and Gulf Coast, reducing overall inventories. That could boost oil prices as refiners draw from existing storage, traders said.

U.S. crude imports in October are expected to be the lowest since September 2015, according to preliminary data from Thomson Reuters Eikon's shipping data.

While the Suezmax market softened slightly this past week, more opportunities in coming weeks should limit further downside, according to a note from shipbroker Charles Weber Co available via Capital Link Weekly on Thomson Reuters' Eikon, citing the resumption of additional exports.

Summary of Weekly Petroleum Data for the Week Ending September 30, 2016

U.S. crude oil refinery inputs averaged over 16.0 million barrels per day during the week ending September 30, 2016, 302,000 barrels per day less than the previous week’s average. Refineries operated at 88.3% of their operable capacity last week. Gasoline production increased last week, averaging 10.0 million barrels per day. Distillate fuel production increased last week, averaging over 4.7 million barrels per day.

U.S. crude oil imports averaged over 7.7 million barrels per day last week, down by 125,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 8.0 million barrels per day, 10.1% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 1.0 million barrels per day. Distillate fuel imports averaged 103,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 3.0 million barrels from the previous week. At 499.7 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories increased by 0.2 million barrels last week, and are above the upper limit of the average range. Finished gasoline inventories decreased slightly while blending components inventories increased last week. Distillate fuel inventories decreased by 2.4 million barrels last week but are above the upper limit of the average range for this time of year. Propane/propylene inventories rose 0.7 million barrels last week and are above the upper limit of the average range. Total commercial petroleum inventories decreased by 11.2 million barrels last week.

Total products supplied over the last four-week period averaged about 19.9 million barrels per day, up by 3.0% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 9.3 million barrels per day, up by 3.2% from the same period last year. Distillate fuel product supplied averaged 3.6 million barrels per day over the last four weeks, down by 8.9% from the same period last year. Jet fuel product supplied is up 6.2% compared to the same four-week period last year.

Attached Files

Aramco price cuts

Saudi Arabia, the world’s largest crude exporter, cut pricing for November oil sales to Asia and Northwest Europe and for most grades to other regions amid a global supply glut.

State-owned Saudi Arabian Oil Co., known as Saudi Aramco, lowered its official pricing for Arab Light crude to Asia by 25 cents a barrel to 45 cents less than the regional benchmark, it said Wednesday in an e-mailed statement. The company had been expected to widen the discount for shipments of Arab Light by 30 cents a barrel, to 50 cents less than the benchmark for buyers in Asia, according to the median estimate in a Bloomberg survey of six refiners and traders.

OPEC last week agreed to trim oil production for the first time in eight years after prices dropped to about half their levels in 2014. The decision meant the group abandoned a two-year-old, Saudi-led policy of letting members pump as much as possible to push higher-cost producers out of the market. That policy has contributed to a global supply glut, with output from Organization of Petroleum Exporting Countries reaching record highs.

“Aramco’s mandate is still to target market share,” Matt Stanley, a Dubai-based oil broker at Freight Investor Services, said by phone. “They are going to be as competitive as possible even if OPEC has agreed to cut production to help prices.”

Record Output

Brent crude has gained about 13 percent since OPEC agreed in Algeria to trim output to between 32.5 million barrels and 33 million barrels a day. The 14-nation group pumped a record 33.75 million barrels a day in September, according to a Bloomberg survey. Saudi Arabia’s production slipped to 10.58 million barrels a day last month from 10.64 million daily in August, according to the survey. Brent gained 1.9 percent to $51.81 a barrel at 2:06 p.m. in London.

Excess crude supply will continue to weigh on prices, JBC Energy GmbH said Monday in a note. Crude supplies may exceed demand by 2 million barrels a day in October as seasonal autumn refinery maintenance curbs demand, the Vienna-based consultant said.

“We see a strong likelihood of increased pressure on prices over the next month,” JBC said.

U.S. Pricing

Saudi Aramco cut the premium for Arab Light crude to the U.S. by 10 cents a barrel to 35 cents a barrel more than the benchmark, according to the statement. Extra Light was the only grade increased for U.S. buyers, with the premium rising 20 cents to $1.80 a barrel. Aramco cut all pricing for Northwest Europe and for the Mediterranean region, widened the discounts on Light and Heavy grades, raised pricing for Extra Light and kept Medium crude unchanged.

Middle Eastern producers are competing with cargoes from Latin America, North Africa and Russia for buyers in Asia, its largest market. Producers in the Persian Gulf region sell mostly under long-term contracts to refiners. Most of the Gulf’s state oil companies price their crude at a premium or discount to a benchmark. For Asia the benchmark is the average of Oman and Dubai oil grades.

Oil Tankers Piling Up in North Sea Highlight Glut Facing OPEC

A pile up of tankers waiting in the North Sea suggests a glut is building again in the market where benchmark crude is traded, highlighting the task facing OPEC as it seeks to rein in a global glut.

At least 10 tankers are at or near locations off the coasts of England and Scotland where they must wait to transfer their cargoes, according to vessel-tracking information compiled by Bloomberg. The increase is happening amid seasonal work at the U.K.’s largest oil field.

"The physical crude market is already showing signs of weakness with floating storage threatening to build up in the North Sea, in spite of ongoing field maintenance," according to a research note from JBC Energy GmbH. It cited the vessel pile up at the ship-to-ship transfer sites as one of the indicators of a surplus.

The Organization of Petroleum Exporting Countries is trying to prop up oil prices despite signs that a worldwide supply surplus isn’t getting any better. The group is now ironing out the details of a pact, announced last week in Algiers, that would curb output to 32.5 million to 33 million barrels a day.

The pact triggered a rally in crude prices, which in turn spurred a rush by U.S. shale producers to lock in future prices.

Libya, Nigeria Rebound

The OPEC accord exempts Iran, which is emerging from international sanctions, from production cuts. While precise details of the plan have yet to be thrashed out, Nigeria has also said it won’t have to comply and Libya is unlikely to be asked to because its oil production is a fraction of what it should be. The deal will be finalized at the end of next month.

European refiners "have more options again now that Nigerian and Libyan loadings are rebounding" and crude and petroleum-product stocks remain high, JBC Energy analyst Eugene Lindell said in an e-mail.

There are signs that oil futures respond to the day-to-day changes in the physical oil market. Brent contracts slumped more than 10 percent from mid-July to early August after it emerged that traders had amassed a fleet of tankers that were storing barrels in the North Sea. By mid August, many of those tankers had gone, and futures more thanreversed their decline.

Daily exports of the crude grades that comprise the Dated Brent benchmark are set to rise to a seven-month high in November, according to loading programs obtained by Bloomberg.

Shell offered Forties crude this week at a discount of as low as 80 cents per barrel below Dated Brent on a ship-to-ship transfer basis. That compares with the last such deal done on September 20 from Total to Shell at a 5 cents premium.

Meanwhile, the structure of contracts for difference -- derivatives used in the North Sea for speculation and hedging -- returned to contango, where prices in the future are higher than those at present. A forward curve in contango is an indication of an oversupplied market where prompt cargoes sell at lower prices than those for later delivery.

Natural gas market ‘mystery’ floats in the Mediterranean

A liquefied natural gas tanker plying the waters of the Mediterranean has created a guessing game for energy traders.

The Maran Gas Delphi has taken a meandering course after loading up on U.S. shale gas a month ago at Cheniere Energy’s Sabine Pass export terminal in Louisiana. The ship anchored off the coast of Greece for several days, prompting speculation that it would deliver its supplies to a port in the region. Instead, the tanker is now bound for the Red Sea, raising the prospect that it may instead travel to the Middle East or Southeast Asia.

RELATED: Gulf Coast booming with propane, butane and now LNG exports

The winding track of the Maran Gas Delphi is a testament to how a gas glut fed by surging production from countries including U.S. and Australia is complicating global trade of the fuel. The rise of so-called homeless LNG, or supplies not already committed to customers, is confounding efforts by traders and analysts to get a grasp of the market and make bets.

“It’s bit of a mystery,” Jason Feer, head of business intelligence at ship broker Poten & Partners in Houston, said of the Maran Gas Delphi. “Normally LNG logistics are pretty well-rehearsed, and having an LNG carrier cooling its heels is expensive.”

Cargoes of LNG not committed to customers will peak at 80 million tons by 2020, up from 50 million now, Feer said. This comes as buyers demand more flexible terms and long-term contracts expire amid the global market oversupply, he said.

The Maran Gas Delphi is not the only example of how LNG cargoes are taking a longer or diverted route to find a home. The Stena Clear Sky, also with a cargo from Sabine Pass, spent a month circling South America before unloading on Mexico’s Pacific coast, instead of taking a shorter route via the now-opened Panama Canal, which would have saved it about 21 days.

More complicated routes highlight how flexible LNG trade is becoming, with more demand for short-term trade to place cargoes in an oversupplied market, said Malcolm Johnson, a Guildford, England-based faculty member of The Oxford Princeton Programme, an energy training provider.

Flexible volumes

U.S. volumes are flexible and don’t have destination restrictions and charter rates are low, which means the buyer wins time to find the best market, he said. A tanker that’s carrying an LNG cargo can effectively be used as a storage.

“What we are likely to experience is that they do divert cargoes at a certain short notice where demand may arise,” Johnson said by phone. “The tanker charter rates are very low, they are extremely low, they give a cargo owner a bit of space to decide which market to potentially move the cargo to.”

Anangel Shipping Enterprises, owner of the vessel, and Royal Dutch Shell, which chartered the ship, declined to comment. A spokeswoman for Cheniere wasn’t immediately able to provide comment. The contract terms of the cargo were unclear.

“Everybody is working to track the vessels,” Feer from Poten and Partners said by phone. “From a trader’s point of view, understanding who’s long, who’s short and where volume is moving is obviously really critical.”

Attached Files

Ukraine Starts Winter With Half-Empty Natural Gas Stores: Chart

Ukraine, a key transit nation for Russian natural gas supplies to European households and power plants, started the six-month winter heating season that began Oct. 1 with the lowest inventories since at least 2014 after halting purchases of the fuel from Russia 11 months ago amid a price dispute. The European Union is seeking gas talks in Moscow before temperatures drop further to ensure the fuel continues to flow smoothly.

Attached Files

KOGAS to sell 330,000 tons LNG to BP for 20 years

Korea Gas Announced on Oct. 5 that IT has signed an Agreement with BP to sell Annual 330,000 tons of Liquefied the Natural Gas Produced AT ITS Offshore Facility in Mozambique for The Next 20 Years.

Through ITS Subsidiary, The State-owned Company About enterprise | owns 10 percent percent stake of Coral South Floating LNG Facility expected to be installed offshore the African country . The facility is operated by Eni East Africa , which owns 70 percent stake in Area 4, where 1.8 billion tons of gas was discovered in 2014, and will begin commercial operations from 2022.

Russian state oil company Rosneft and Indonesian state energy company Pertamina have agreed a refinery joint venture in the Southeast Asian country, which may also get stakes in upstream projects in Russia, Rosneft said on Wednesday.

Pertamina is seeking overseas producing energy assets as Indonesia's domestic oil output has been declining since the early 1980s. The company is also developing domestic processing facilities to cut fuel imports.

Indonesia, which rejoined OPEC last year, consumes 1.6 million barrels per day (bpd) and produces around 0.85 million bpd, according to a review conducted by BP.

Rosneft, which is expected to get a 45 percent stake in the 300,000 barrels-per-day refinery, wants to expand abroad, especially in a region dominated by OPEC producers from the Gulf.

The new Tuban refinery will have a crude processing capacity of 300,000 bpd and is targeted for completion in 2021.

Rosneft said that Pertamina could also get up to 20 percent in the offshore Northern Chayvo project off Russia's Pacific island of Sakhalin and up to 37.5 percent in the onshore Russkoye field in Siberia.

As well as its first venture with Russia, Pertamina is looking at energy projects in Iran, Saudi Arabia, UAE, Gabon, Kazakhstan and Azerbaijan, adding to its overseas assets in Malaysia, Algeria and Iraq.

Pertamina plans to upgrade four of its existing seven refineries, and develop at least two new oil processing plants by 2023, more than doubling its domestic capacity to 2.3 million bpd from 1 million bpd currently.

Resolute Energy Corporation today reported that it has entered into a definitive agreement (the "Acquisition Agreement") with Firewheel Energy, LLC, a portfolio company of EnCap Investments, toacquire certain oil and gas properties located in Reeves County, Texas, for a purchase price of $135 million. The transaction is expected to close on October 7, 2016.

The Firewheel Properties consist of 3,293 net acres in our highly productive Delaware Basin operating area, and include interests in thirteen horizontal and fifteen vertical wells, which produce approximately 1,200 net Boe per day. Approximately 95% of the acreage and substantially all of the production and proved reserves are located within the Resolute-operated Mustang project area in Reeves County. The remainder of the acreage is also in Reeves County. The Firewheel Properties contain estimated proved reserves of 6.2 MMBoe with PV-10 of $45.8 million, using strip pricing at June 30, 2016. The acquisition also includes Firewheel's interest in the Earn-Out Agreement (to which we are also a party) with Caprock Permian Processing LLC and Caprock Field Services LLC (collectively, "Caprock"). Following the closing of the acquisition, Resolute will receive 100% of all payments from Caprock under the Earn-Out Agreement.

The purchase price for the acquisition is $135 million, consisting of $90 million payable in cash and the issuance to Firewheel of 2,114,523 shares of our common stock, equal to $45 million, based on 90% of the volume weighted average price of our common stock as traded on the NYSE for the 15 trading days ending on October 4, 2016. We expect to finance the cash portion of the acquisition price with the net proceeds of a private offering of a newly created class of preferred stock of the Company, and borrowings under our Revolving Credit Facility (which is currently undrawn).

The acreage to be acquired represents an approximately 25% increase in our net acreage in Reeves County while leaving our gross acreage position essentially unchanged as the Company already owns interests in all of the same properties. The completion of this acquisition will result in a higher interest in the production and cash flow generated from our operated wells, further leveraging the work of our field staff.

Canada’s oil industry to lose $10 billion this year

Canada’s oil extraction industry is on track to post a second consecutive year of shortfalls — to the tune of $10 billion — on the back of ongoing revenue woes, combined with a slower than anticipated cost cutting response, a local think-tank said Tuesday.

According to the Conference Board of Canada’s latest outlook for the industry, the crude sector’s losing streak will last about three years, from the last quarter of 2014 through to the second quarter of 2017.

Investment cutbacks are expected to continue this year and next, which will result in lower production levels.

The report also estimates that profit margins will hit record lows this year to a negative 19% and that while they will improve from 2017 onwards to roughly 4% in 2020, return to profitability remains uncertain.

In terms of production, the board expects it to contract slightly this year for the first time since the 2008 global financial downturn.

When it comes to investment in the sector, the think-tank is not positive either. It says that only last year producer slashed to $25 billion in expenditure and that the cutbacks expected to continue this year and next. From 2014 to 2017, industry investment will have been cut by an estimated $38 billion, it noted.

That pullback in investment will, in turn, result in lower production levels, the board warns, adding that it expects Canada’s crude output to fall by 1% this year. This, mostly as a direct consequence of disruptions caused by wildfires in Fort McMurray earlier in the year, as well as ongoing investment cutbacks.

Recent data from Statistics Canada shows the country’s economy shrank in the second quarter of the year touching levels not seen since 2009, mostly due to Alberta fires.

Total pipeline gas exports through Nord Stream, Yamal, and Brotherhood rose 13% month on month and 7% year on year to 10.108 Bcm in September, the highest monthly flows seen since March and the fifth-highest total recorded for a calendar month.

Flows breached the 350 million cu m/d mark on several occasions last month, with gas throughput via the Brotherhood pipeline -- transiting Russian gas to Slovakia via Ukraine -- rising to their highest in over two years early last month due to Nord Stream maintenance.

Brotherhood flows in September were steady month on month at 4.260 Bcm, but were well up on September 2015 levels of 3.498 Bcm.

Flows via the Nord Stream pipeline -- transiting Russian gas direct to Germany via the Baltic Sea -- rose to 3.368 Bcm last month, higher than the 2.488 Bcm seen during August due to a lighter maintenance schedule in September compared to the previous month.

Flows via the Yamal pipeline -- transiting Russian gas to Germany via Poland and Belarus -- were again steady at 2.480 Bcm in September, with the pipeline typically used at the full 84 million cu m/d full capacity.

Total Russian flows via these pipelines for the first nine months of the year stood at 85.603 Bcm, 13% higher when compared to the January-September, 2015, period and over 12 Bcm up on the same time in 2014.

Moreover, after Norwegian pipeline gas exports fell to their lowest in over five years in September, Russian gas supplies stand nearly 9 Bcm higher than Norwegian gas supplies during the first nine months of 2016.

Russian gas flows during the Winter 2016-17 delivery period are set to continue at high levels, with oil-indexed gas prices under Gazprom's structure ending September below hub levels for both Q4 2016 and Q1 2017, incentivizing high nominations from customers during the winter period.

SandRidge Energy Emerges from Reorganization with Approximately $525 Million of Liquidity

Relisted on New York Stock Exchange and Resumed Trading Under Ticker "SD"

$3.7 Billion of Debt Eliminated

SandRidge Energy, Inc. today announced it has emerged from Chapter 11, having satisfied all the necessary provisions of its Plan of Reorganization (the "Plan"). SandRidge received approval to relist on the New York Stock Exchange in conjunction with its emergence and resumed trading of newly issued common stock on October 4, 2016, under the ticker symbol "SD".

Combining its unrestricted cash balance with the availability under its first lien credit facility following emergence, SandRidge exits its restructuring with approximately $525 million in total liquidity.

New Capital Structure Summary

SandRidge's new capital structure consists of a $425 million first lien revolving credit facility ("RBL") (maturing in 2020) and approximately $282 million in mandatorily convertible notes, bearing no interest and converting at any time at the option of the holders or mandatorily at the earlier of certain events or four years from the effective date of the Plan. As previously disclosed, SandRidge's pre-petition second lien secured and general unsecured claim holders receive 100% of the newly issued common equity in the reorganized company.

Nucor, Encana end drilling deals, enter into lease agreement

A major steelmaker and the oil and gas producer Encana have ended deals compelling them to jointly develop thousands of natural gas wells in western Colorado’s Piceance Basin when gas prices are high enough.

In their place, Nucor has bought a 49 percent oil and gas lease interest from Encana on about 54,000 acres in the Piceance, with Encana retaining a 51 percent controlling interest in that acreage.

The companies both said ending their joint venture gives them more flexibility in decisions about where to make capital investments. In the short term, at least, that could mean a delay in any resumption of drilling by Encana locally. Under the joint venture with Nucor, Encana would have been obligated to drill once natural gas prices rose to a predetermined level.

“We wanted to have the flexibility to really direct our capital where we felt we would have the highest (profit) margins,” Encana spokesman Doug Hock said.

For now, anyway, that means spending money in what Encana considers its four core areas — two basins in Texas and two in Canada that are more liquids-rich than the Piceance, which primarily produces natural gas.

As for Nucor, the new transactions with Encana “preserve Nucor’s long-term access to low cost gas resources in support of Nucor’s raw material strategy. We think this … is a win-win for both companies,” John Ferriola, Nucor’s chairman, chief executive officer and president, said in a news release.

Encana and Nucor have ended a drilling agreement reached in 2010 and a larger one that came two years later. They involved sharing in the upfront cost of drilling wells in exchange for Nucor gaining a working interest in the wells that are drilled.

The 2012 agreement held the potential for Encana to drill more than 4,000 wells over 20 years on some 50,000 acres of federal leases stretching from Garfield County into Rio Blanco County. Nucor said at the time that it expected to invest $542 million over the following three years and about $3.64 billion over the estimated 13- to 22-year term of the agreement.

Nucor, based in North Carolina, is a heavy consumer of natural gas and got involved with Encana as a hedge against the possibility of rising natural gas prices. The joint venture wasn’t designed to ship the gas produced to its factories, but rather was intended to ensure that if gas prices go up, Nucor also is invested on the gas supply side.

Encana and Nucor eventually suspended drilling under the joint venture under terms allowing for that if prices fell too low. By late 2013 Encana decided to stop drilling altogether in the Piceance, and it hasn’t drilled locally since. A Nucor official later told The Daily Sentinel that as many as 300 wells probably had been drilled under the joint venture before work was suspended. Nucor said Tuesday it is keeping all producing wells it owns.

Hock said Nucor’s new lease ownership covers the same acreage that was involved in the 2012 agreement. Encana, as majority owner, would decide if and when to drill on the acreage, and Hock said Nucor would have a 49 percent ownership of proceeds from any drilling.

Nucor said in its release that the new ownership structure “provides Nucor full discretion on its participation in all future drilling capital investment.”

Nucor also sold its half-interest in Hunter Ridge Energy Services LLC to Encana. Hunter Ridge was formed by the two companies to provide gas gathering and water services.

Nucor didn’t disclose in its news release the dollar amounts involved in the lease and Hunter Ridge transactions.

Select Sands Corp. is pleased to announce that it has entered into a binding agreement with Tutle Holding, LLC and Steve Hackmann, Ozark Premium Sand, LLC ("OPS") pursuant to which Select Sands' wholly owned subsidiary, American Select Corp., will purchase certain of OPS's equipment and shall have the option to purchase OPS's dry processing plant, operating equipment, saleable inventory, and customer lists amongst other miscellaneous assets owned by OPS.

Included in the assets in respect of which the Company will have an option to purchase is a 26-acre fully operational drying facility with storage located within 50 miles of Select Sands' "Sandtown" quarry in Arkansas, USA. The 26-acre facility is located on the Union Pacific Rail Line. If the option is exercised, this transaction will transform Select Sands into a fully integrated, self-sufficient Tier 1 sand producer with capacity to process more than 600,000 tons per year with an excellent logistics and storage advantage. In addition, the facility can be easily expanded to increase the amount of sand that can be processed.

Rasool Mohammad, President, CEO and Director of Select Sands states, "We are very pleased to come to terms on this transaction that is very favourable for both parties moving forward. In the energy market, Tier-1 regional (40/70 and 100 mesh) sand is in high demand right now, and the market is tightening for this finer sand. Our timing to become a new supplier of high-purity, finer mesh sand couldn't come at a better time for our shareholders."

Pursuant to the terms of the agreement, Select Sands will pay US$500,000 upon signing of the agreement to the vendors in respect of the purchase of certain heavy equipment. Select Sands will take title to these assets upon payment of the US$500,000.

Select Sands will then have 60 days to complete its due diligence on the remaining assets that are subject to the agreement. If Select Sands is satisfied with its due diligence, then before the end of the due diligence period it must pay an additional US$250,000 to the vendors for certain specified additional heavy equipment and US$250,000 as a payment for the option to acquire the remaining assets within the period expiring on the one year anniversary of the date of payment of the above referenced US$250,000 option payment. The purchase price for the remaining assets subject to the option will be US$3,317,000, after deducting the US$250,000 option payment.

As per the June 2015 PEA report by Tetra Tech of Golden, Colorado, USA and Vancouver, BC, Canada, the Sandtown property has a pre-tax net present value of US$160 million and a post-tax net present value of US$92 million. The PEA was completed on a portion of the current silica sand mineral resources (see the Select Sands' June 10, 2015 News Release).

Within this PEA, the CAPEX for the drying plant, equipment, storage and loadout was ~US$32M, whereas the total purchase price that encompasses the vast majority of this CAPEX totals US$4,317,000.

Mr. Mohammad continues, "This transaction demonstrates our commitment to become a fully integrated producer in the most accretive way possible and demonstrates our aligned interests with shareholders."

The Company is fully funded to make the first two payments from treasury and is in the position to fully evaluate all financing options to finalize the proposed transaction as the Company continues to increase sales and ramp production.

Canada Oil Sands in Race With Shale, Batteries for Survival

Canada’s oil-sands industry is in a race with other forms of crude production and emerging technologies such as electric cars to remain a relevant energy source in the coming decades, according to consultancy Deloitte LLP.

Among various scenarios, oil-sands producers face the risk of a “forced transition” away from oil and natural gas as power generation is dominated by solar panels and wind turbines and as electricity replaces oil as a transportation fuel, Deloitte said in a report released Tuesday. Most of Canada’s oil and gas would be stranded and only the lowest-cost producers would survive by spending on innovative technology.

“Companies should reflect on what actions they might take today to provide resilience in the face of different future scenarios,” Andrew Swart, Daniel Rowe and Paul Craig wrote in the report.

Companies including Suncor Energy Inc., Imperial Oil Ltd. and competitors have beenslashing operating costs as they wait for crude prices to rise in order to deploy the latest, cost-saving equipment that will make oil production less carbon intensive. Canada’s industry is hampered by its higher costs and lack of access to global markets, which has depressed prices for commodities.

Foreign Investment

Another possible scenario would see hydrocarbons remain a significant source of global energy as commodity prices remain competitive and with only incremental improvements in battery technology, the report said. Foreign investment in Canadian oil and gas, as well as new pipelines, would allow companies to remain competitive in global markets.

No matter what, companies must focus on innovation to improve performance and engage with stakeholders to retain their social license to operate, the authors said.

Canada’s oil industry is on track to post a combined pre-tax losses of C$10 billion ($7.6 billion) this year, following a record loss of C$11 billion in 2015, according to the Conference Board of Canada. The industry will likely return to profit next year, the group said in its industry outlook.

Oil Major BP Buys First Iranian Oil Since Lifting of Sanctions

Iran’s state-owned oil company sold natural gas condensate to BP Plc for the first time since sanctions were lifted in January, marking the country’s re-emergence as one of the world’s top suppliers of crude oil and natural gas liquids.

National Iranian Oil Co. will supply South Pars condensate to BP for loading between September and October, said an NIOC official, asking not to be identified because of internal policy. The shipment may be used by one of BP’s own refineries or resold to other users, the official said by phone.

A London-based spokeswoman for BP declined to comment on the deal when contacted by phone.

The sale is a milestone for OPEC’s third-largest producer, which has been ravaged by sanctions targeting its nuclear program. Iran has vowed to recover its lost market share by restoring its crude oil output to pre-sanctions levels of slightly over 4 million barrels a day. The country also wants torevitalize its refining and petrochemical industries to improve the quality of fuel sold on the domestic market and wean itself off imported oil products.

Iran is also working with traders such as Trafigura Group, which lifted a cargo of Iranian Heavy in June in an attempt to expand its reach into the Chinese independent refining market. Royal Dutch Shell Plc shipped a cargo of Iranian crude to Europe in July, while France’s Total SA was the first oil major to resume purchases of Iranian oil in February this year.

Alaska Oil Known Reserves May Have Just Grown 80% on Discovery

Alaska’s oil reserves may have just gotten 80 percent bigger after Dallas-based Caelus Energy LLC announced on Tuesday the discovery of 6 billion barrels under Arctic waters.

The light-oil reserves were found in the company’s Smith Bay leases between Prudhoe Bay and Barrow along the Arctic shore, according to a statement from Caelus. As much as 2.4 billion barrels is estimated as recoverable, according to a release issued by the company. That compares with the state’s proved reserves of 2.86 billion barrels in 2014, almost 8 percent of the U.S. total, Energy Department datashow.

“This discovery could be really exciting for the state of Alaska,” Caelus Chief Executive Officer Jim Musselman said in the statement. “It has the size and scale to play a meaningful role in sustaining the Alaskan oil business over the next three or four decades.”

Alaska’s oil output has been gradually declining, to 483,000 barrels a day last year from a peak of more than 2 million barrels a day in 1988, Energy Department data show. The last major field brought online was Alpine in 2000, which averaged 62,000 barrels a day in September, Alaska Department of Revenue data show.

Peak Production

Caelus said its newly discovered field could produce as much as 200,000 barrels a day. That compares with 483,000 barrels a day pumped in Alaska last year, Energy Department data show. The Eagle Ford shale region, the largest U.S. field, yielded 238,000 barrels a day in 2013.

The discovery of light oil was made after seismic data was collected and two wells were drilled this year, the company said. Another well will be drilled in early 2018, Casey Sullivan, a company spokesman, said in a phone interview. The discovery would be the biggest in four decades, the company said. Prudhoe Bay, the state’s biggest field, was discovered in 1967.

A driller on the North Slope needs oil at about $40 a barrel on average to be profitable, Sarah Erkmann, external affairs manager at the Alaska Oil and Gas Association, said in a phone interview. Oil traded at about $49 a barrel today in New York.

“At these depressed prices, that makes it very challenging,” she said.

New wave of power plants is fuelling U.S. gas demand

The United States is experiencing a structural increase in gas demand with more gas-fired power stations operating more hours per year and consuming a record volumes of gas.

But domestic gas production is turning down, with output nearly 4 percent lower in July 2016 compared with July 2015 ("Falling U.S. gas output meets stronger demand", Reuters, Oct 3).

Growing demand for gas and shrinking supplies are not sustainable, so gas prices will have to rise to encourage more drilling and limit the use of some gas-fired power plants.

U.S. power producers had 448 gigawatts of gas-fired generation capacity in July 2016, an increase of 25 gigawatts since the end of 2012, according to the Energy Information Administration (tmsnrt.rs/2dOroBg).

Installed gas-fired capacity is scheduled to grow by another 11.5 gigawatts to 459 gigawatts by the end of 2017, when it will be almost 9 percent higher than five years earlier.

Most of the extra capacity uses combined-cycle technology. Total gas-fired capacity will have risen nearly 9 percent between 2012 and 2017 but combined-cycle will increase by almost 14 percent over the same period (tmsnrt.rs/2dOrHvX).

Historically, most gas-fired power plants burned gas in a boiler to raise steam (similar to a coal-fired plant) or combusted it directly in a gas turbine (similar to an aircraft jet engine).

Steam turbines and especially combustion turbines waste lots of heat and are relatively inefficient and expensive ways to generate electricity.

But they can ramp production up and down more quickly than coal-fired steam turbines, which made them ideal for meeting short periods of peak power demand in summer and winter.

Used mostly in peaking mode, gas-fired steam turbines were used for less than 12 percent of the time on average in 2015 while combustion turbines were used less than 7 percent of the time.

Combined-cycle units, however, are designed to operate far more efficiently: gas is first burned in a combustion turbine and then the exhaust heat used to raise steam in a boiler.

Both the turbine and the boiler can be used to drive generation sets, enabling more of the fuel's energy content to be converted into electricity.

Combined-cycle units are designed to provide baseload throughout the year rather than just during periods of peak demand.

The average combined-cycle plant operated more than 56 percent of the time in 2015, according to the Energy Information Administration.

CAPACITY FACTORS

Capacity factors for combined-cycle plants have been trending upward over the last few years as they replace coal-fired units thanks to stricter emissions regulations and falling gas prices.

The average gas-fired combined-cycle plant operated for the equivalent of 4,932 hours at full power in 2015, up from 4,489 hours in 2012, an increase of almost 10 percent.

Average coal unit operation dropped to the equivalent of 4,783 hours from 4,981 hours over the same period ("Average utilization for natural gas combined-cycle plants exceeded coal plants in 2015", EIA, April 2016).

Capacity factors at combined-cycle units continued to increase in 2016, while coal-fired power plants sat idle more of the time, thanks to low gas prices.

The proliferation of combined-cycle plants with high capacity factors is driving a big structural increase in gas consumption and tightening the gas market.

Unusually high temperatures across the most populous parts of the United States since the end of May helped drive record gas combustion by power producers this summer (tmsnrt.rs/2dKGyre).

But with more gas-fired power plants being installed and running for more hours, underlying gas demand has been increasing, whatever the weather.

With more combined-cycle capacity due to come online, gas consumption will continue to increase, other things being equal.

The combination of rising gas consumption with stagnating or falling gas production is clearly unsustainable in the medium term (tmsnrt.rs/2dKHFan).

Gas prices will have to rise to reverse the slump in gas production and cut capacity utilization at combined-cycle plants to conserve fuel.

The EIA forecasts gas use in the power sector will decline by 2.3 percent in 2017 as rising gas prices spur a modest switch back towards coal ("Short-Term Energy Outlook", EIA, September 2016).

Non-OPEC participation in deal would cut 1.2 million barrels per day: Venezuela

Participation by non-OPEC countries in a deal to stabilize oil prices would remove a total of 1.2 million barrels per day from an oversupplied market, Venezuela's Oil Minister Eulogio Del Pino said on Tuesday.

The Organization of the Petroleum Exporting Countries (OPEC) agreed last week to bring its production to between 32.5 million and 33.0 million bpd by cutting some 700,000 bpd.

The group, which meets in Vienna on Nov. 30 to finalise the deal, has invited Russia and other non-OPEC producers to join in making cuts.

"With the deal between OPEC countries, some 700,000 bpd are taken out of the market, and by adding non-OPEC, it's 1.2 million bpd," Del Pino said in a televised broadcast.

Price hawk Venezuela, which is suffering a deep economic crisis worsened by a fall in oil prices, has been pushing for a deal for months and has said it expects non-OPEC countries to support efforts to boost oil prices.

Enerplus seeks buyer for Marcellus natural gas assets: sources

Canadian energy producer Enerplus Corp (ERF.TO) has put its natural gas assets in the U.S. Marcellus shale region up for sale, according to three sources familiar with the situation.

The assets could fetch about $500 million, the sources said, speaking on condition of anonymity as the matter is not public.

Enerplus, which owns oil and natural gas assets in Canada and the United States, expects the sale to make its asset portfolio more geographically concentrated and allow it to pay down debt, the sources said.

The company's net debt as of June 30 was about C$700 million ($530 million).

Enerplus could also make an acquisition with the money, one of the sources said.

After the Reuters report, Enerplus shares turned positive and rose as much as 3.8 percent. There were trading at C$9.02, up 2.7 percent, in afternoon trade.

The Marcellus assets, in Pennsylvania, have drawn interest from parties in the United States and Asia, the sources said, adding that private equity firms are the most likely buyers.

Enerplus, which calls the Marcellus shale gas project one of the most economic dry gas plays in North America, did not respond to a request for comment.

The company says on its website that it has oil assets in the Williston Basin in North Dakota, where it expects to spend C$145 million this year. That compares with C$20 million for the Marcellus project.

In a recent investor presentation, Enerplus cited "over $1.2 billion of net divestment proceeds since 2010," which it said has helped focus the portfolio. Its website lists the Marcellus asset as one of its focus areas.

About 35 percent of the company's production in 2016 is expected to come from its Marcellus shale business, according to the website.

BHP petroleum briefing

Attached Files

Oil prices rise on report of U.S. crude stock draw

Oil prices rose in early trading on Wednesday after a report that U.S. fuel inventories may have fallen for a fifth straight week, but contracts remained near the $50 marker where many traders currently see fair value for crude.

U.S. West Texas Intermediate (WTI) crude oil futures were trading at $49.14 per barrel at 0430 GMT, up 45 cents, or 0.9 percent, from their last settlement.

Traders said the higher prices were largely a result of a report by the American Petroleum Institute (API) late on Tuesday showing that U.S. crude inventories likely fell for a fifth straight week, declining by 7.6 million barrels. [API/S]

The U.S. government's Energy Information Administration (EIA) will report official stockpile numbers on Wednesday, although analysts polled by Reuters expect the EIA to report a stock build of 2.6 million barrels for the week ended Sept. 30. EIA.

In international oil markets, benchmark Brent crude futures were trading at $51.29 per barrel, up 42 cents, or 0.8 percent.

Gary Ross, founder and executive chairman at the New York-based consultancy PIRA, said that a planned deal by members of the Organization of the Petroleum Exporting Countries (OPEC) to cut output would likely lead to only a modest price increase.

Jason Gammel of U.S. investment bank Jefferies said implementation of the OPEC deal "may prove unsuccessful" due to rivalries within the group but he added that "the mere threat of a production cut should put a floor under oil prices until the next OPEC meeting on November 30."

Beyond the uncertainty of an OPEC-deal, Gammel said "security conditions in Nigeria and Libya seem to us the most acute uncertainties in the market," adding that if output in any of these countries recovered "that would mean a very hefty cut from the remaining OPEC members if they want to meet the output target."

ING bank also warned not to read too much into the planned OPEC production cut before details were agreed.

"This is still only a plan, and no final agreement has been made," the bank said, adding that even modest cuts face hurdles given that Iran, Nigeria and Libya have campaigned for exemptions, which would mean members such as Venezuela and Saudi Arabia would have to stomach larger cuts.

The Dutch bank said that higher prices "are possible within the coming weeks to next few months, although limited."

OPEC sights set for now on $50-60 per barrel oil - PIRA's Ross

OPEC producers have their sights set on a sustained oil price of $50-$60 per barrel, a modest ambition for the first cut in supply by the oil exporting group in eight years, says one of the industry's top forecasters.

Benchmark U.S. oil prices CLc1 have risen around $4, or around nine percent, to over $48 per barrel since the Organization of the Petroleum Exporting Countries (OPEC) agreed last week to shave output.

"You don't manage the market unless you have a price in mind," said Gary Ross, founder and executive chairman at the New York-based consultancy PIRA.

"They are being cautious, they want to see what will happen with shale. But OPEC's price aspirations only go up over time. They don't go down."

The deal marks the return to supply caps for the producer group after a brutal two-year free-for-all when OPEC members ditched output targets and pumped more than the market needed in a price war that bloodied U.S. shale producers.

U.S. oil output fell to around 8.7 million barrels per day in July, the lowest since May 2014 and down over 730,000 bpd on the year, mostly as shale producers hit by low oil prices cut output.

Ross challenged the assumption that a higher price could be self-defeating for OPEC because it will encourage shale producers to boost output.

"We're not necessarily about to be overwhelmed by shale oil," he said. "The timing of this is quite deliberate, OPEC is doing this heading into winter and at a time when supply from non-OPEC producers is down."

Peak northern hemisphere energy demand during the cold season provides OPEC with a window to reach its price aspirations, Ross said. Shale producers will need four to six months to bring new production online, and that may take longer in areas where cold weather prevents work.

After letting thousands of employees go over the past two years, it will take time for shale producers to build up operations and costs will rise quickly, he added.

The impact of fast-rising costs on shale producers was likely another factor in OPEC's thinking, Ross said. OPEC producers have less variable costs and so will benefit more from the uplift in oil prices than shale producers, he said.

While the price rout hurt OPEC's competitors, the group's oil ministers were under pressure from their own central bankers and finance ministers to do something to reverse the impact of low prices on their own revenues, Ross said.

Many have had to cut budgets and the generous benefits as they adjusted to the longest and deepest oil price rout since the 1980s.

The $4 rise in prices is already worth over $100 million a day in additional revenue for OPEC producers pumping around 33 million bpd of crude.

OPEC kingpin Saudi Arabia was not just dressing up a seasonal variation in output as a supply cut, Ross said. The kingdom typically reduces output after summer, when it no longer needs to burn crude for power generation to feed demand for air conditioning.

"There is a lot more to it than that," he said. "The policy to push for market share is over. It's a matter now of going back to managing the market."

Mozambique, Eni ink LNG supply deal with BP

Italy’s Eni and Mozambique have reportedly signed a 20-year deal with UK-based BP for the supply of liquefied natural gas from the Coral FLNG project, moving the project further forward.

The final investment decision for the Coral FLNG project is expected to be reached by the end of the year, Reuters reports citing a statement by the state-owned Empresa Nacional de Hidrocarbonetos (ENH).

LNG World News contacted Eni, BP and ENH seeking comments on the LNG sales contract. We did not receive any response by the time this article was publsihed.

Eni secured the approval from the Mozambique government for the development plan of the Coral FLNG project that is expected to produce around 3.4 mtpa, in January this year.

The approval relates to the first phase of development of 5 trillion cubic feet of gas in the Coral discovery, located in the Area 4 permit.

The giant discovery, located approximately 80 kilometers offshore of the Palma bay in the northern province of Cabo Delgado, is estimated to contain around 16 trillion cubic feet (TCF) of gas in place.

The plan of development, the very first one to be approved in the Rovuma Basin where 85 Tcf of gas have been discovered, foresees the drilling and completion of 6 subsea wells and the construction and installation of a floating LNG facility, Eni said after receiving the approval.

Eni is the operator of Area 4 with a 50 percent indirect interest, owned through Eni East Africa (EEA), which holds a 70 percent stake of Area 4.

The other partners are Galp Energia, Kogas and ENH with a 10 percent stake each. CNPC owns a 20 percent indirect interest in Area 4 through Eni East Africa.

PTT to sign more favourable gas contract with BP, Shell

PTT, Thailand's state-owned oil and gas conglomerate, will sign a 15-year contract for liquefied natural gas with Shell Eastern Trading and BP Singapore before the end of the year.

LNG imports will begin in April, a year later than initially planned. PTT postponed an earlier contract because the sharp drop in global oil and gas prices opened the way to cheaper purchases through spot contracts. Energy demand in Thailand has also been weakened by the sluggish economy.

The new contract is awaiting cabinet approval and priced in a way that should save PTT roughly 100 billion baht ($2.88 billion) over the period, Chief Executive Tevin Vonvanich said on Monday. He said the new formula is more resilient to price fluctuations.

Thailand meets 70% of its energy needs with natural gas and with diminishing reserves in the Gulf of Thailand is increasingly turning to imported LNG and to investing in foreign gas fields.

PTT's first long-term LNG purchasing agreement was signed in 2015 when it entered a 20-year contract with Qatar Gas, the world's largest LNG producer, to buy 2 million tons annually.

PTT has operated an LNG receiving terminal in Rayong on the eastern seaboard of the Gulf of Thailand since 2011. The terminal's second phase development is due for completion by the end of the year and for commissioning in March just before the contract with Shell and BP kicks in. The terminal's capacity will more than double to 11.5 million tons per year.

Growth in propane exports drove U.S. petroleum product export growth in first half of 2016

In the first half of 2016, the United States exported 4.7 million barrels per day (b/d) of petroleum products, an increase of 500,000 b/d over the first half of 2015 and almost 10 times the crude oil export volume. While U.S. exports of distillate and gasoline increased by 50,000 b/d and nearly 140,000 b/d, respectively, propane exports increased by more than 230,000 b/d. Propane surpassed motor gasoline to become the second-largest U.S. petroleum product export, after distillate.

Although total U.S. petroleum product exports grew, export destinations remained largely unchanged. Mexico,Canada, and the Netherlands received the greatest volumes of U.S. petroleum products in the first half of 2016, importing 775,000 b/d, 579,000 b/d, and 271,000 b/d, respectively. U.S. petroleum products tend to stay in the Western Hemisphere. In 2015, approximately 60% of total petroleum product exports remained within the Western Hemisphere, down slightly from 65% in 2005.

Distillate exports averaged 1.2 million b/d in the first half of 2016, an increase of 50,000 b/d from the same period of 2015. Central and South America accounted for the largest share of U.S. distillate exports, averaging more than 620,000 b/d in the first half of 2016, up more than 30,000 b/d from the same period of 2015. The largest single destination overall for U.S. distillate exports was Mexico, which averaged 147,000 b/d in the first half of 2016.

U.S. propane exports increased from 562,000 b/d in the first half of 2015 to 793,000 b/d in the same period of 2016. Exports to Asia and Oceania accounted for 94% of this growth. Japan imported the most U.S. propane at 159,000 b/d in the first half of 2016, an increase of 111,000 b/d from 48,000 b/d in the same period of 2015. U.S. exports of propane to Panama, however, fell from 41,000 b/d in the first half of 2015 to 7,000 b/d in the first half of 2016.

The large increases in propane exports to Japan and decreases in propane exports to Panama could be a result of reduced ship-to-ship transfer activity. Some of the propane exports from the United States that undergo ship-to-ship transfers will cite the location of the transfer and not the final destination of the propane. This often results in larger-than-actual export numbers for the countries where the ship-to-ship transfers take place and in less-than-actual numbers for some final destinations.

Gasoline exports increased 138,000 b/d in the first half of 2016 compared with the first half of 2015. North America (Canada and Mexico) accounted for most of the growth, with an increase of 92,000 b/d. Similar to U.S. distillate fuel exports, Mexico represented the largest single recipient of U.S. gasoline exports at 363,000 b/d in the first half of 2016, up from 283,000 b/d in the first half of 2015. As part of the energy reforms passed in 2013, Mexico liberalized its energy sector, allowing market participants other than the state company Petroléos Mexicanos (Pemex). In January 2016, as part of the liberalization process, Mexico began to allow companies besides Pemex to import fuels, resulting in increased exports from nearby refineries along the U.S. Gulf Coast. Canada was the second-largest recipient of U.S. gasoline at 66,000 b/d in the first half of 2016, up from 55,000 b/d in the first half of 2015.

Attached Files

India’s Biggest Oil Processor to Boost Refinery Expansion Plan

Indian Oil Corp. is scaling up an expansion plan for its biggest refinery in northern India at a cost of 150 billion rupees ($2.3 billion), as it races to meet demand in one of the world’s fastest-growing crude consumers.

India’s top refiner will expand its Panipat refinery to 25 million metric tons a year (500,000 barrels a day) from the current 15 million tons, according to Sanjiv Singh, director of refineries. The state-run processor previously planned to boost capacity to 20.2 million tons.

“Fuel demand growth has been very strong and India’s excess capacity is very small,” Singh said in New Delhi. “We have to keep adding capacities.”

Increased use of trucks, cars and motorbikes spurred by rapid economic expansion has made the world’s second-most populous nation a bright spot for global oil demand, drawing interest from Saudi Aramco to Rosneft PJSC. Local refiners are racing to add capacity amid rising fuel consumption.

India’s fuel consumption rose about 11 percent last year, surpassing China’s growth of 7 percent, making the South Asian nation the biggest driver of global energy demand, Kapil Dev Tripathi, the top bureaucrat in India’s oil ministry, said Monday.

Six Years

Indian Oil plans to spend 1.84 trillion rupees through 2022 to expand its refining, pipelines and distribution infrastructure. The state-run refiner will add annual capacity of 24 million tons to its existing refineries over the next six years, Chairman B. Ashok said last month.

Indian Oil last week said it would spend about 83 billion rupees to increase the capacity of its Barauni plant in eastern India by 50 percent, along with a petrochemicals unit.

“Next, we will take up expansion of Panipat, Gujarat and Mathura refineries,” Singh said. “The Panipat expansion would take about 42 months to complete after the project is approved.”

Indian Oil can currently process 80.7 million tons of crude a year from its nine plants and two owned by its unit Chennai Petroleum Corp. It accounts for 35 percent of the nation’s total output, according to its website.

South Africa Picks Ports for $3.7 Billion LNG Infrastructure

South Africa will invest $3.7 billion at the ports of Richards Bay and Coega to build infrastructure for a gas-to-power program aimed at easing the country’s dependence on coal.

A plant at Richards Bay will generate 2,000 megawatts of electricity from liquefied natural gas imports, with another 1,000 megawatts at the Coega industrial development zone, the Department of Energy said in a memorandum on Monday. The government will seek bidders to manage the project, underpinned by a power-purchase agreement between the winning applicant and state electricity utility Eskom Holdings SOC Ltd.

The program, which coincides with low LNG prices, will create wider opportunities for chemical industry and domestic applications, Trade and Industry Minister Rob Davies told investors at a conference in Cape Town. Apart from the 3,000 megawatts generated at the ports, another 600 megawatts will come from the appointment of a strategic partner for a gas-fired plant and a further 126 megawatts is allocated to a domestic gas program.

Richards Bay initially will require 1 million tons a year of LNG and Coega 600,000 tons a year, Karen Breytenbach, head of Independent Power Producers Procurement Program Office, told reporters Tuesday. The ports will each require 25 billion rand ($1.8 billion) in infrastructure, she said. The program is looking to hedge the LNG, which is priced in dollars.

Demand for LNG throughout the country could increase to more than 10 million tons a year after a decade, according to studies by the Department of Energy. That includes long-term demand in KwaZulu-Natal province of 3.1 million tons, Eastern Cape at 3.9 million tons, with the addition of a gas market in Gauteng, Mpumalanga and Free State of 3.2 million tons.

“The program is designed to ensure that the LNG import and regasification facilities are complementary to the development of indigenous gas and/or development of a regional gas pipeline network,” the department said.

Pipeline Network

South Africa’s existing pipeline infrastructure is limited, with Johannesburg-based Sasol Ltd. using a link to import gas from Mozambique to Gauteng province. Another line was constructed to pipe gas to the steel industry and to markets in Richards Bay and Durban.

The term of a power-purchase agreement with Eskom for the projects is anticipated to be 20 years from the commercial operation date, according to the memorandum. Prequalification for the program will be announced in April, after bidders make submissions in February. The final request for proposals is expected in August, the Energy Department said.

Oxy Permian update or lack of! Company being schtum.

Attached Files

Nigerian Militants Are Getting Ready to Strike Oil Again

If the Nigerian government wants to fight militants blowing up oil pipelines, it should send troops into the creeks and mangrove swamps of the Niger River delta. Not the city.

That’s the suggestion of Babalola Olarewaju, a taxi driver who plies the airport route in Port Harcourt, the largest city in the restive oil-rich region.

“We’re talking about people who blow up pipelines in the night and then disappear,” said Olarewaju, 41, as he perched on the hood of his rickety cab outside the Le Meridien Hotel in the city center, referring to three T-72 tanks, Nigeria’s main battle tank, parked about a mile away. “What has a tank got to do here in the city?”

Dozens of tanks and 3,000 more troops have joined existing forces in and around Port Harcourt in the past month, a sign the government is pulling out the stops to quell a new wave of violence in Africa’s second-largest oil producer. So worrisome are the attacks that OPEC allowed Nigeria to be exempt from production curbs the cartel agreed on last week, the oil ministry said.

A six-week-old cease-fire show signs of weakening: The Niger Delta Avengers, responsible for more than 90 percent of all attacks this year, on Sept. 23 claimed responsibility for an attack, its first since July 24, on a key supply pipeline to Royal Dutch Shell Plc’s Bonny export terminal, a few miles outside Port Harcourt, in a statement on its website. The authenticity of the website, which has proved reliable before, couldn’t be verified.

There’s a lot at stake. Exxon Mobil Corp. is planning to resume some shipments at its Qua Iboe terminal, the country’s largest, at the end of September and expects repairs on the 400,000 barrel-a-day main export line will be completed in December. Shell also expects its Forcados terminal, out since February, to come back on line any time now. The company earlier this month lifted a delivery halt on its Bonny terminal shipments it had imposed in August after saboteurs breached its main supply pipeline.

The crucial challenge for the government is to appease a plethora of militant groups, some of whom never signed on to the cease-fire, such as the Niger Delta Greenland Justice Mandate. President Muhammadu Buhari, elected last year, is loathe to negotiate with the militants and is skeptical they are adhering to the truce. While Oil Minister Emmanuel Kachikwu, who helped broker the truce and also hails from the delta region, favors peace talks, the country’s security chiefs are averse to negotiation. Army chief Lieutenant-General Tukur Burutai would rather deploy more troops to put down the conflict. At least an additional 10,000 will be sent out in 2017, he said Sept. 9.

More Troops

“I do not see a willingness to engage,” said Ledum Mitee, a lawyer and Niger delta minority rights activist who’s part of the peace talks. “The response of the government is to send more troops to the region. There is a growing frustration within various groups that the government is not ready for negotiations and this may lead them back to attacking pipelines.”

In all, output is now estimated to average about 1.5 million barrels a day “at best,” Kachikwu said on Aug. 12. That’s potentially 23 percent lower than last year.

The resurgence of armed conflict in the delta mirrors a 2006 to 2009 campaign by the Movement for the Emancipation of the Niger Delta, or MEND. Attempts by then-president Umaru Yar’Adua to quell the militancy using troops escalated the violence. Attacks were curbed only after a state pardon and monthly stipend was granted to fighters willing to disarm. Violence resurfaced after Buhari stopped the payments and ended pipeline security contracts worth millions of dollars that former President Goodluck Jonathan negotiated with the militants.

Pipeline Knowledge

This has come to haunt the government. The militants today are more sophisticated and their attacks more precise. Led by the Niger Delta Avengers, the groups, now familiar with the layout of oil pipeline networks from their security operations, have in six months struck companies including Shell, Exxon Mobil, Chevron Corp. and Eni SpA where it hurt most: hard-to-fix export pipelines and oil-gathering hubs. So far this year, Forcados, Qua Iboe, Brass River and Bonny oil terminals have made declarations of force majeure -- a legal term that allows companies to miss export commitments -- after attacks on crude supply pipelines.

“A resumption of hostilities in the Niger delta would be disastrous for the government,” said Malte Liewerscheidt, senior Africa analyst at U.K. security consultants Verisk Maplecrost. “Sending the military is no solution.”

Attached Files

Petrobras, Statoil extend partnership for old wells - sources

Petrobras, Statoil extend partnership for old wells - sources

Petróleo Brasileiro SA and Norway's Statoil ASA are expanding an existing partnership to help the Brazilian state-controlled company arrest declining production at aging wells in the offshore Campos Basin, two people with direct knowledge of the plan said.

In late August, Petrobras and Statoil signed a memorandum of understanding that has since evolved to targeting aging wells. Both firms are discussing under which terms Statoil could get stakes in some fields in exchange for fresh investment and technological cooperation, the people said.

Press representatives for Petrobras did not have a comment. The sources asked not to be identified because the talks remain private.

However, in an emailed statement to Reuters, Oslo-based Statoil acknowledged the plan, adding that it is too early to elaborate on the evolution of the talks.

The decision underscores steps by Chief Executive Officer Pedro Parente to rationalize capital spending at Petrobras, and cope with the impact of low oil prices and a sweeping corruption scandal involving the company.

The Campos Basin, which was responsible for about 85 percent of Brazil's oil output five years ago, accounts now for 58 percent. Petrobras produces about 80 percent of Brazil's oil and is responsible for developing massive offshore oil finds in a region known as the Subsalt Polygon, which first produced oil in 2008.

The move comes two months after Statoil agreed to pay $2.5 billion for a 66 percent stake in Carcará, one of Petrobras' largest oil and gas prospects. Recently, the companies signed a deal in which they said would collaborate on existing fields in Brazil's Campos and Santos Basins..

BUSINESS PLAN

The Subsalt Polygon is an offshore region near the coast of Rio de Janeiro, where several of the world's largest recent oil discoveries have been made.

Last month, Petrobras cut planned investments for the 2017-2021 period by 25 percent in a drive to reduce the largest debt burden among global oil producers, at $130 billion, and revive investor confidence battered by years of over spending.

Capital spending plans for existing Campos Basin wells suffered the most with the cuts, one of the people said.

The 2017-2021 business plan lowered the estimate for the rate of decline of production in the Campos Basin to 9 percent a year. Petrobras had a prior estimate of a decline between 12 percent and 15 percent.

The plan included the need for production partnerships in the Campos Basin, especially to revive output in the basin's Marlim field.

Breakthroughs are fuelling up the Bakken

Operators have been saying the Bakken is getting better and better, but North Dakota Department of Minerals Director Lynn Helms had the numbers to show it. Not only are today’s wells vastly superior to wells of even two years ago, Helms said during the annual conference of the North Dakota Petroleum Council, but they now have a lifespan that is five years longer.

“Initial production (on new wells) has increased from 1,100 barrels a day to 1,500,” Helms said.

Coupling that with the additional five-year lifespan, that means 25 percent more recovery from every well bore.

The new methods that created better productivity are also creating opportunities for economical refracs of old-school wells even at current prices — an “iteration” Helms called amazing.

An iteration is a successive process in which the next solution is based on the last, but a little bit better than before.

“You are getting more of the reservoir and using no greater footprint than in 2014,” Helms said. “You are still iterating, and it amazes me.”

Helms estimated there are between 8,000 and 8,500 wells drilled with older technology, many of which could be good refrac candidates.

Previous to Helms, a Whiting Oil representative talked about his company’s foray into refracs, and how his company is developing methodologies to determine which wells are good candidates for the process. Prior fracs didn’t use as much sand and had less efficient fractures than what is possible today.

“Data is mounting for why you want to refrac before you do,” Charles Ohlson, a petroleum engineer with Whiting Petroleum Corporation, said.

Those kinds of things mean more opportunities for further reiterations, Helms pointed out.

“There’s just a huge amount of iteration in well design and in well completion that is going on,” he said. “It is far from settled science.”

Helms has developed several scenarios for the lifespan of the Bakken play.

The endpoint of the Bakken shows 65,000 wells and a peak rig count of 150 in 2023. That uses a price of $50 to $60 oil to get there — a price point at which most of the Bakken’s return on investment has been shown to be fairly reasonable, according to state figures shared by Justin Kringstad, with North Dakota Pipeline Authority.

In a slow year such as this, an estimated 2,500 wells don’t get drilled, Helms said. The question is, when will they get drilled? In one scenario, they are drilled in 2035, but what if they are drilled as soon as oil prices pop back up, say mid 2017?

“When I go out and talk to communities and students about their anticipated needs for housing, sewer or water, I tell them to keep the scenario in mind, because this is the scenario that brings back crew camps,” Helms said.

And it also brings revenue for building out infrastructure needs.

In another scenario, oil stays low for longer and only the core of the Bakken gets drilled.

Helms couldn’t exhaust the core in a reasonable time frame without adding more rigs to the model. Even then, it still took 15 years to exhaust the core, showing that the play has plenty of life to make it through the downturn.

Oil in the $50 to $60 range will make the state’s 900 drilled but uncompleted wells highly economic, Helms said, and will ramp up the number of frac crews operating. That number for now is in the range of five to 11. At peak prices, there were 50 frac crews operating in the Bakken.

“Sixty dollar oil makes the Bakken superior to other plays,” Helms said. “Even to the Permian and Eagle Ford. So that is when you will see drilling rigs go back into service.”

However, even then, you still won’t see as many rigs, Helms said, and you can thank iteration for that, too. Today’s rigs are now achieving 25 wells in a year, versus eight or nine in 2009.

“It’s just an indication of what kind of technology is out there,” Helms added.

Multi-well pads, new bit technology, new motor technology, new mud technology — these are all getting their own iterations, improving the efficiency and lowering the costs of getting along in the Bakken.

Drill times are now down to an average of 12 days, with three of that waiting for cement to set.

Attached Files

Funds managed by affiliates of Apollo Global Management, LLC (NYSE:APO) (together with its consolidated subsidiaries, “Apollo”) and Post Oak Energy Capital, LP (“Post Oak”) announced today that Double Eagle Lone Star LLC (“Double Eagle”), and Veritas Energy Partners Holdings LLC (“Veritas Energy”) have entered into a definitive merger agreement, creating one of the largest pure play exploration and production companies focused on the Permian’s Midland Basin. Double Eagle was previously a subsidiary of Double Eagle Energy Holdings II LLC (“Double Eagle II”), a portfolio company of Apollo Natural Resources Partners Funds I and II, and Veritas Energy was previously a portfolio company of investment partnerships managed by Post Oak.

The newly combined company, which is called Double Eagle Energy Permian LLC, has more than 63,000 core Midland Basin net acres (over 70% operated) located predominantly in Midland, Martin, Howard and Glasscock counties, and a team with extensive experience drilling and operating wells in the region.

Double Eagle Energy Permian will be headquartered in Fort Worth, Texas, and Cody Campbell and John Sellers, the current Co-Chief Executive Officers of Double Eagle II, will serve as the Co-Chief Executive Officers of the new company with Hollis Sullivan, the current President of Veritas Energy, serving as Chairman.

John Sellers and Cody Campbell commented, “We believe combining the highly complementary Midland Basin acreage positions of Double Eagle and Veritas Energy creates a truly world class asset in the core of the most economic basin in North America.”

Hollis Sullivan added, “With the strength of the new company’s combined management team and its operated, drill-ready acreage position, Double Eagle Energy Permian is uniquely positioned for rapid growth and expansion in the region.”

Shale Oil Firms Hedge 2017 Prices in ‘Droves’ After OPEC Rally

Independent oil companies are using the post-OPEC rally to hedge their price risk for next year, banks and consultants said, a trend that’s likely to be viewed with concern from Saudi Arabia to Venezuela.

The clamor to hedge -- locking in future cash flows and sales prices -- could translate into higher U.S. oil production next year, offsetting an output cut that the Organization of Petroleum Exporting Countries outlined in Algiers last week. Shale firms in particular would enjoy extra income to pay for additional drilling.

“We are seeing significant producer flows which early estimates suggest could be the highest we have seen all year,” Adam Longson, commodity strategist at Morgan Stanley in New York said in a note to clients.

Crude futures surged by almost $5 a barrel since OPEC surprised traders by agreeing to trim output at a gathering in Algiers on Sept. 28.

Harry Tchilinguirian, head of commodity research at BNP Paribas SA in London, said on Friday that OPEC had thrown a “lifeline” to U.S. shale firms, prompting them to hedge “in droves.” The bank has “seen many queries coming through” from producers, he said.

The West Texas Intermediate 2017 calendar strip -- an average of future prices next year that’s often used as a reference for hedging activity -- rose above $50 a barrel to its highest since August on Monday. “When calendar 2017 pricing rises into the low-to-mid $50s, as it is doing now, producer hedging rises materially,” Longson said.

U.S. shale producers used a similar rally to hedge their prices in May, when the WTI 2017 calendar strip also rose above $50 a barrel. The current activity comes after industry executives told investors in July and August they planned to use any window of higher prices to lock-in cash flows for next year.

"We would like to be a little bit further hedged than we are today," Pioneer Natural Resources Co. Chief Executive Officer Tim Dove said back in July, noting his company has locked in prices for up to 55 percent of its 2017 exposure. “I’d like to see us get that number up as we go towards at the end of this year.”

U.S. independent oil companies have only hedged 16 percent of their price exposure for 2017, compared with 39 percent for the rest of this year, according to Houston-based boutique investment bank Tudor, Pickering, Holt & Co. "We expect hedge book conversations to tick up during the next round of quarterly calls," it said in a note to clients on Friday.

U.S. shale companies and other independent exploration and production companies usually reveal their level of hedging with a quarter delay. Nonetheless, anecdotal pricing activity already suggests their presence in the market.

The WTI price curve, for example, has flattened over the last week, with spot prices rising more than prices for delivery next year, suggesting producer selling in 2017 and beyond. The spread between the WTI contract for immediate delivery and a year forward narrowed on Friday to minus $4.12 a barrel, from minus $4.77 a barrel before the OPEC meeting. The trend continues further down the curve too, with the spread between oil for delivery in Dec. 2017 and Dec. 2018 also contracting sharply after the decision in Algiers.

At the same time, the open interest in the WTI June 2017 contract has jumped nearly 10 percent over the last week, while the December 2018 contract rose 6.5 percent, another indication of hedging activity. Open interest across all WTI contracts rose by 66,000 lots -- the equivalent of 66 million barrels of oil -- from Tuesday to Friday last week, according to preliminary CME data. The total volume of crude futures on ICE and Nymex combined hit a record on Wednesday, the day of the Algiers meeting at which OPEC members agreed on a plan to limit output.

“Every time prices get above the $50 range we see a lot of activity coming in from producers selling into the rally,” said Hamza Khan, an analyst at ING Bank NV in Amsterdam.

China Gasoline exports reach NY.

Chinese gasoline will reach the U.S. East Coast for the first time in nine years as a surge in New York prices helps ease a glut in Asia.

Trafigura Group Pte. is said to be shipping about 375,000 barrels of gasoline to New York from China and Hong Kong aboard the tanker Marylebone, according to a person familiar with the delivery who asked not to be named. The ship delivered Korean alkylate in Houston for the trading company last week before continuing on to the Northeast, U.S. Customs data show.

Attached Files

Perisai Bondholders Reject Oil Rig Contractor’s Proposal

Perisai Petroleum Teknologi Bhd., a Malaysian offshore oil rig contractor, failed to convince a group of bond investors to agree to its debt restructuring plan.

More than 70 percent of investors who voted on Monday rejected the company’sproposal to extend the maturity of the bond to Feb. 3, 2017, according to Cheng Fong Kiew, a bondholder present at the meeting.

Over 20 bondholders gathered at the basement of an office tower in Singapore’s central business district to vote on the plan to prolong maturity of its S$125 million ($91.6 million), 6.875 percent bond due today. Bond investors last week demanded immediate repayment after talks with the company collapsed.

“Yes, it’s our responsibility that we bought the bonds but the company can’t just brush us aside,” said Cheng, who owns S$500,000 of Perisai bonds. “Trust has been eroded.”

Southeast Asia’s oil and gas industry is being hobbled by a decline in crude prices and slowing global economic growth. Swiber Holdings Ltd. roiled the market when it defaulted on S$460 million of local-currency notes, while shippers including Rickmers Maritime are seeking to reorganize debts.

Perisai’s head of corporate planning Lai Swee Sim, who represented the company at today’s meeting, declined to comment. The notes were last quoted at 55 Singapore cents on the dollar, according to DBS Bank Ltd. prices.

Shares in Perisai have dropped 24 percent in Sept., outstripping the broader KLCI market that has declined 1.5 percent.

OPEC oil output hits record on Iraq, Libya boost

OPEC's oil output is likely to reach its highest in recent history in September, a Reuters survey found on Friday, as Iraq boosted northern exports and Libya reopened some of its main oil terminals.

The increase comes despite lower output in top exporter Saudi Arabia and this week's agreement by the Organization of the Petroleum Exporting Countries in Algeria to limit supply to support prices, its first such decision since 2008.

Supply from OPEC has risen to 33.60 million barrels per day (bpd) in September from a revised 33.53 million bpd in August, according to the survey based on shipping data and information from industry sources.

The rise in output could add to scepticism about OPEC's ability to allocate its new production target of between 32.50 million and 33 million bpd, a task ministers left until a meeting in November. Oil rallied towards $50 a barrel on Thursday but was trading near $49 on Friday.

"The agreement still leaves hard and difficult negotiations for the individual caps to be set," said Bjarne Schieldrop, chief commodities analyst at SEB.

"Now, with an OPEC curb on the cards for the first time in eight years, Brent crude is not even able to lift above $50. At least not yet."

Supply has risen since OPEC in 2014 dropped its historic role of fixing output to prop up prices as Saudi Arabia, Iraq and Iran pumped more. Production has also climbed due to the return of Indonesia in 2015 and Gabon in July as members.

The membership changes have skewed historical comparisons. September's supply from OPEC excluding Gabon and Indonesia, at 32.65 million bpd, is the highest in Reuters survey records starting in 1997.

In September, the increase was led by Iraq and Libya. Iraqi state oil firm SOMO and Iraq's semi-autonomous region of Kurdistan began jointly exporting crude from the Kirkuk oilfield again. This lifted Iraqi supply to market to 4.43 million bpd in September, according to the survey.

In Libya, the National Oil Corporation opened three previously blockaded ports, allowing AGOCO, an NOC subsidiary that operates mainly in eastern Libya, to boost output.

Supply in Saudi Arabia has edged down from the record high reached earlier in the summer, sources in the survey said.

Supply in Iran, OPEC's fastest source of production growth earlier this year after the lifting of Western sanctions, has held steady this month as output nears the pre-sanctions rate. Iran is seeking investment to boost supply further.

Angolan output slipped because the Plutonio field was shut for part of the month.

There was no sign yet of higher supply from Nigeria, where attacks on oil installations have cut output. Supply should rise in October if efforts for a restart of Qua Iboe and Forcados crude exports come to fruition.

The Reuters survey is based on shipping data provided by external sources, Thomson Reuters flows data, and information provided by sources at oil companies, OPEC and consulting firms.

Qatargas, the world's largest LNG producer, will start operations at its new Ras Laffan 2 condensate splitter by the end of this month, doubling the Gulf state's capacity to process condensate, two sources with knowledge of the matter said on Monday.

The 146,000 barrel per day (bpd) facility had been due to open in September but was delayed due to technical problems, traders said.

It will process deodorized field condensate (DFC) and low sulphur field condensate to extract mostly naphtha and middle distillates.

Condensate exports from Qatar will drop from 500,000 bpd to about 350,000 bpd when the 146,000-bpd splitter starts operating, an official at Qatar Petroleum, Qatargas's state-owned majority shareholder, has said. That will enable the Gulf state to soak up some of its condensate at home as it faces growing competition for condensate sales overseas from U.S. and Iranian light oil shipments.

Commissioning of the new splitter is "99 percent" complete and an imminent handover to operator Qatargas is likely to see the plant start up "within the next two weeks," a Doha-based source, who declined to be named because he was not authorised to speak publicly, told Reuters.

Japan's Chiyoda Corp is building the refinery in a joint venture with Taiwan's CTCI Corp.

"We are at the final moment. There were no technical problems from our end," Chiyoda's general manager in Qatar, Toshiyuki Ito, told Reuters, but would not confirm a start-up date.

Qatari state-marketer Tasweeq withdrew offers for at least 1.5 million barrels of prompt November-loading DFC last week, traders with knowledge of the matter said, possibly indicating the splitter is likely to open imminently.

Initial offers for November-loading cargoes had indicated that the condensate splitter was more likely to start operations in November than October as the oil firm was seen reducing its November feedstock requirements by opting to sell prompt cargoes, traders said.

Tasweeq sold 2 million barrels of DFC for end-October loading prior to its offers for November-loading condensate supplies.

East Libyan oil firm AGOCO says production rises to 320,000 barrels per day

Libya's Arabian Gulf Oil Company (AGOCO) said on Monday that its production had risen to 320,000 barrels per day (bpd), from 290,000 bpd late last week.

The increase had come after production at Sarir field rose to around 200,000 bpd, and production at Nafoura had reached 29,000 bpd, spokesman Omran al-Zwai said. He added that AGOCO could reach its year-end target of 350,000 bpd if the Bayda field came back on line.

AGOCO, a subsidiary of the National Oil Corporation (NOC) that operates mainly in eastern Libya, has roughly doubled production since forces loyal to eastern commander Khalifa Haftar seized blockaded oil terminals last month and the NOC announced it would reopen them for exports.

Progress on opex – but will it stick?

The last two years have clearly been a challenging and, at times, painful period for everyone in the upstream sector. The dramatic fall in oil prices has forced the industry to look hard at capex plans and the efficiency of operating assets and functions, with significant downward pressure on rates.

There is evidence that the industry’s efforts are delivering some significant cost reductions. We are seeing reductions in both project development costs and in operating efficiency – our analysis shows that opex per boe, for example, has declined by 11% globally between 2014 and 2015.

As the industry works on plans for 2017, there are two important questions operators must address: do existing actions and plans go far enough to reset the cost base; and will these actions deliver cost reductions that stick. As we are seeing signs of an emerging OPEC production agreement, and the associated uptick in oil prices, we think that it is critical to challenge whether the cost reductions of the last 18 months truly are sustainable or whether we are about to see the start of the next upcycle in costs.

We conducted an upstream sector Cost Survey over the last three months. We received over 290 responses from senior people from across the industry, both operators and the supply chain. The results show that the industry is generally pessimistic when it comes to the sustainability of cost reductions. Less than 45% of respondents believe reductions achieved in the last 12 months to be sustainable and structural – a view shared both by the supply chain and operators. The timing is also interesting as the survey was completed in early September, before this week’s OPEC announcement.

Respondents also indicated that the focus of cost reduction over the next year would be on fundamentally tactical measures, such as retendering and renegotiation of contracts. There was little evidence that the respondents were expecting to see widespread adoption of measures which would take out cost for all parties in the supply chain.

The financial health of the supply chain provides an interesting perspective on the sustainability question. The impact of reductions in rates and activity levels has been a dramatic deterioration in Oil Field Service (OFS) company margins since 2014. There is no doubt that re-evaluating contracts and renegotiating rates is a rational strategy for operators, but it is questionable whether OFS players will tolerate such low margins when the market recovers. History suggests that there will be a push towards higher rates.

It is not only the suppliers who are anticipating a return to price increases. Interestingly 26% of respondents, from operators and the supply chain, expect to see price inflation in 2017 compared to only 8% of our 2015 survey respondents who expected to see inflation in 2016.

Really understanding the composition of the cost reductions over the last two years will be an important step for operators to start to manage this sustainability risk.

We will be publishing a perspective giving a fuller picture of the cost survey results and our views on the sustainability question in October. If you would like to discuss how we can help you to explore this question for your organisation, please get in touch.

Operating cost: has the oil industry really moved the needle? The dramatic fall in oil prices – from over US$100 a barrel in mid-2014 to less than US$30 a barrel in early 2016 – has left the oil industry scrambling to contain the damage. Upstream operators are deferring investment...

Attached Files

Marathon Oil sells non-operated assets for $235 million

Marathon Oil Corporation announced that the Company has signed an agreement for the sale of certain non-operated CO2 and waterflood assets in West Texas and New Mexico for $235 million, excluding closing adjustments. The properties averaged approximately 4,000 barrels of oil equivalent per day in the first half of 2016. The effective date of the transaction is Sept. 1, 2016, and closing is expected by year end.

Since August 2015, Marathon Oil has announced or closed non-core asset sales in excess of $1.5 billion.

Strike threat for Norway plants

Norwegian union Safe is threatening strike action later this week by workers at three onshore plants unless it secures a pay agreement in state-mediated talks with employers, potentially hitting gas supplies to the UK.

Mammoth Energy Services, Inc. today announced the commencement of its initial public offering of 7,500,000 shares of its common stock at an anticipated initial public offering price of between $15.00 and $18.00 per share.

Certain selling stockholders named in the registration statement are offering an additional 250,000 shares of common stock. In addition, the underwriters have a 30-day option to purchase up to an additional 1,162,500 shares of common stock, at the same price per share, all of which would be sold by the selling stockholders.

Mammoth Energy will not receive any of the proceeds from the sale of the shares by the selling stockholders.

SM Energy Announces Additional Asset Divestitures

SM Energy Company announced today that it has engaged Petrie Partners to explore a sale of certain leasehold assets in the Williston Basin. The assets to be sold include approximately 54,500 net acres, consisting of the Raven/Bear Den acreage and effectively all lease-holdings in the basin outside of the Company’s Divide County program.

President and Chief Executive Officer Jay Ottoson comments: “We have outlined a simple strategy to focus on our Tier 1 assets in the Permian Basin and operated Eagle Ford. As part of this strategy, we are continuing to core up our portfolio, such that we can concentrate investment dollars in the highest return programs and bring that value forward through accelerated activity. Raven/Bear Den is a terrific asset that provides attractive full-cycle returns, and we believe it will be of more value to a company that will actively pursue its near-term development.”

Separately, the Company has closed on previously announced divestitures of assets located in New Mexico, North Dakota, Montana, and Wyoming, with associated net production of approximately 3,300 Boe per day, for net proceeds after purchase price adjustments and fees of approximately $186.7 million.

Iran's total crude oil and condensate sales likely reached around 2.8 million barrels per day in September, two sources with knowledge of the matter said, nearly matching a 2011 peak in shipments before sanctions were imposed on the OPEC producer.

The run-up from shipments of around 2.5 million bpd in August comes mainly from condensate, a light oil excluded from OPEC supply quotas that is often produced with natural gas and can be used to make naphtha for petrochemical production.

Iran sold 600,000 bpd of condensate for September, including about 100,000 bpd shipped from storage, to meet robust demand in Asia, the two sources said. September crude exports increased slightly from the previous month to about 2.2 million bpd, they said.

Iran, along with Libya and Nigeria, is allowed to produce "at maximum levels that make sense" as part of any output limits in a surprise deal reached last week by the Organization of the Petroleum Exporting Countries (OPEC).

Still, the Middle Eastern producer has surprised the market by ramping up its oil output faster than expected, to 3.63 million bpd in August, according to OPEC, up a quarter from end-2015 since sanctions were lifted in January.

"Iran cannot produce much more than the present, so around 3.7 million bpd may be the max," said Fereidun Fesharaki, chairman of consultancy FGE.

Even if Iran's output hit 3.8 million bpd - as an oil official said it had in September - it would not be able to sustain that volume as decline rates at its oilfields are about 400,000 bpd each year, Fesharaki said.

National Iranian Oil Co (NIOC) officials did not immediately respond to an emailed request for comment.

Iran has said it plans to raise its output to 4 million bpd, although other analysts agreed production has probably peaked for now because investments to pump out more oil are lagging.

SOUTH PARS CONDENSATE TO PUSH GROWTH

Condensate instead of crude oil will drive Iran's export growth for the remainder of 2016, thanks to developments at its giant South Pars gas field, the sources said.

NIOC drew on condensate stocks from floating storage and onshore tanks in September to help meet growth in demand from China, South Korea, Japan and India.

Iranian ports loaded 2.153 million barrels of crude and 486,000 bpd of condensate in September, according to Thomson Reuters Supply Chain and Commodities Research. That put the month's total at 2.639 million bpd - excluding the condensate loaded out of storage - up from 2.472 million bpd in August, the Reuters data showed.

Condensate sales could reach 800,000 bpd in October, in excess of production at about 550,000 bpd, one of the sources said, suggesting further draws from floating tankers.

"Korea was the main demand driver for the growth. Japanese and Indian plants were also raising imports," said one of the two sources with knowledge of the matter from Beijing, adding that China's Sinopec has also boosted its offtake of condensate since August.

Iran will sell another 2 million barrels, or about 66,000 bpd, of South Pars condensate each month to Hyundai Chemical in Daesan between October and December, the two sources said.

Iranian condensate will meet about 70 percent of the feedstock demand at a new Hyundai Chemical splitter jointly operated by Hyundai Oilbank Co and Lotte Chemical .

A Hyundai Oilbank spokesman declined to comment.

According to trade flow data on the Thomson Reuters Eikon terminal for Iran condensate that discharged in September, about one-third went to South Korea, with the rest going to the United Arab Emirates, India, China and Japan.

Iran's South Pars condensate is usually sold at small premiums to Dubai quotes, free-on-board, much lower than Qatari condensate, which sells at premiums of $2-$3 a barrel, trade sources said.

US Exports of petroleum products climb

Exports of petroleum products climbed significantly last year, driven by increases in shipments of gasoline, propane, and distillate fuels, such as diesel and heating oil, the Energy Department said.

Petroleum exports climbed nearly 500,000 barrels a day in 2015 from the previous year, the Energy Department said. Exports of distillates, the biggest segment of U.S. petroleum exports, rose 85,000 barrels a day to about 1.2 million barrels a day, the Energy Department said. The top destination for the fuel was Mexico.

Gasoline exports averaged about 618,000 barrels a day last year, up by 68,000 a barrels a day from 2015. Mexico, again, was the biggest customer.

Propane exports climbed by 193,000 barrels a day to 615,000 barrels a day, much of it headed to Asia. Propane exports to Asia more than doubled to 220,000 barrels a day from 82,000 barrels a day in 2014, the Energy Department said.

U.S. Drilling Rebound Plows Ahead as Oil Rigs Are Added

U.S. oil producers put more rigs back to work, marking the highest level of activity since February as crude markets headed for a second monthly gain.

Rigs targeting crude in the U.S. rose a fifth consecutive week, up 7 to 425, Baker Hughes Inc., said on its website Friday. Explorers have added 109 rigs since the end of May. Natural gas rigs rose by 4 to 96 this week, bringing the total for oil and gas up by 11 to 522. Three of the four biggest oil fields expanded this week.

West Texas Intermediate for November delivery rose 26 cents, or 0.5 percent, to $48.09 a barrel at 1:43 p.m. on the New York Mercantile Exchange. Prices are up 8.1 percent this week and down 0.5 percent this quarter.

"The push up in prices close to $50 is triggering a response in the rig count. Not sure if we’re seeing a significant enough increase, but if we continue to add rigs, then production levels would rise, which would have a softening effect on prices," Gene McGillian, an analyst at TFS Energy Futures, said by phone. "We have a long way to go until then. The rig count still remains at lower levels than before."

Regional Gains

West Texas’ Permian Basin added 3 rigs for a total of 204 operating in what has been the busiest drilling region during the market slump. The Williston Basin in North Dakota added 2 rigs to total 30, and D-J/Niobrara in Colorado added 1. The Eagle Ford Shale in South Texas remained unchanged, according to the Baker Hughes data.

Oil rigs have continued their climb as members of the Organization of Petroleum Exporting Countries agreed this week to cut production for the first time in eight years in an effort to boost global prices.

If OPEC manages to implement the cut, then it could reinforce the current rebound in drilling, Andrew Cosgrove, an analyst at Bloomberg Intelligence, wrote Sept. 29 in a report. Lower OPEC production would support the case for another 133 rigs being added from now through the end of 2017, he wrote. "Pricing power could come for land drillers in late 2017 or early 2018 if oil remains supported and rig additions continue."

Oil prices rose this week after OPEC’s informal talks in Algiers, surging the most in more than five months and leading to a second monthly gain. OPEC’s proposal calls for a cut in production to 32.5 million to 33 million barrels a day, but many industry experts are concerned that members won’t be able to cooperate enough to implement the cut.

Russian oil output jumps 4 pct in September to a new record

Russian oil output jumped by almost 4 percent in September from the previous month to 11.11 million barrels per day (mbp), a new post-Soviet record-high, as companies ramped up drilling amid improved oil prices, Energy Ministry data showed on Sunday.

The oil output rose amid the talks between the leading global producers, including Russia, to curb production in order to support oil prices, depressed by oversupply.

Russian Energy Minister Alexander Novak said on Friday that Russia will find mechanisms and instruments needed to freeze oil production should the country reach an agreement with the Organization of the Petroleum Exporting Countries on limitingoutput.

In tonnes, Russian oil output reached 45.483 million versus 45.309 million in August. Last month, oil output in million barrels per day stood at 10.71.

The rise was led by world's top listed oil producer, Rosneft, whose output rose by 2.6 percent month-on-month, as well as Gazprom Neft, which showed a 5.2 percent jumpin production last month.

The jump in Russian production comes not only thanks to conventional oil deposits but also as Kremlin oil champions Rosneft and Gazprom Neft are increasing output ofhard-to-extract oil, despite Western sanctions on Russian shale projects.

Analysts from Swiss bank UBS forecast a rise of 2.7 percent next year of Russia's overall oil production.

"Production growth is to be driven by new projects ramp-up and better production management at conventional brownfields (also supported by tax benefits)," they said last month.

Russia's oil production peaked at 11.41 million bpd in 1988 when it was still part of the former Soviet Union, according to the International Energy Agency. Russia accounted for 90 percent of Soviet output.

Natural gas production in Russia was at 51.33 billion cubic metres (bcm) last month, or 1.71 bcm a day, versus 45.29 bcm in August.

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Thai PTTEP to invest at least $1.7 bln in 2017 to maintain output

Oct 3 PTT Exploration and Production Pcl, Thailand's largest oil and gas explorer, plans to invest at least $1.7 billion in 2017 to maintain its production at the same level as last year, chief executive said.

PTTEP, the upstream exploration business of PTT Pcl , aims to produce around 323,000 barrels of oil equivalent per day next year, the same level as last year, Somporn Vongvuthipornchai told reporters.

Hit by weaker oil prices, PTTEP has focused on cost cutting and expects its cost per unit to fall by more than 10 percent to between $31 to $32 a barrel this year after a decline to $29 to $30 a barrel in the first half, he said.

FERC Tells Ohio Valley Connector Project to Open the Valves

The Ohio Valley Connector (OVC) project is a proposed natural gas pipeline system approximately 37 miles long running from northwestern West Virginia into southeastern Ohio.

Equitrans, a subsidiary of EQT Midstream which is itself a subsidiary of EQT the driller, is building the pipeline. We reported in July 2014 that the project was green lighted.

At that time, EQT CEO David Porges said the pipeline will interconnect with both the Rockies Express Pipeline and the Texas Eastern Pipeline and will provide about 1 billion cubic feet (Bcf) per day of capacity.

In July 2015 we ran a story disclosing that the main customer for the new pipeline is one of EQT’s biggest competitors, Range Resources. Fast forward to today. The pipeline’s project cost has gone up, to $415 million. But the really good news is that the pipeline is now built, and the Federal Energy Regulatory Commission (FERC) has just given EQT permission to turn it on…

Utica Condensate Begins Flowing Through Cornerstone Pipeline

In December 2013 MDN first reported a new $250 million pipeline on the way in the Utica Shale from Marathon Petroleum Corporation, the largest refiner in the Utica Shale region.

The Cornerstone pipeline will stretch nearly 50 miles from the MarkWest cryogenic processing plant in Cadiz, OH northwest connecting to M3’s fractionator plant in Scio and M3’s cryogenic processing plant in Leesville along the way as it terminates and connects to Marathon’s refinery in Canton, OH.

The pipeline will carry, at various times, crude oil, condensate and natural gasoline. From Canton, Marathon plans to move condensate and NGLs to Midwest refining centers and into Canada.

In July the company said Cornerstone would be online by the end of this year (seeMPLX Cornerstone NGL Pipe Done by End 2016, New Projects Coming). Yesterday the pipeline went online–at least part of it did–when Cornerstone flowed condensate from Cadiz and East Sparta…

US DUCS

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Mulling options: Petronas may sell out of PNW LNG or put it on ice

Malaysian giant Petronas is reportedly contemplating a sale of a majority stake in the Pacific NorthWest LNG project that has recently been awarded the clearance by the Canadian Federal government.

However, with the nod, the government attached 190 legally binding conditions in order to mitigate the environmental impacts of the C$36 billion (US$27.25 billion) project.

Immediately after receiving the approval, Pacific NorthWest LNG’s president, Adnan Zainal Abidin, noted that moving forwards to the financial investment decision depends on a complete project review to be conducted over the coming months by PNW LNG and its shareholders.

The low oil prices have hit Petronas’ profits, forcing the company to cut costs as well as jobs, and now the economics of the PNW LNG project is in doubt with dropping LNG prices.

The company could sell its majority stake in the project, Reuters reports, citing sources close to the matter.

Gas prices, costs and returns are set to be reviewed before a final decision is made, according to the report. It is also possible for Petronas to suspend the project until gas prices start to recover and Petronas is able to secure favorable long-term contracts.

The proposed Pacific NorthWest liquefaction facility will comprise an initial development of two LNG trains of approximately 6 million tons per annum each, and a subsequent development of a third train of approximately 6 mtpa.

Partners in the project are Sinopec, JAPEX, Indian Oil Corporation and PetroleumBRUNEI.

Gas Angst

For those who fear the worst for the prospects for gas in Europe, Dusseldorf was not a reassuring place to be these last few days. That’s because the highlights of the tenth annual European Gas Summit organised by Platts (part of S&P Global) in the German city persistently returned to the themes that demand forecasts are always too high, that the industry is behind the curve in responding to public concerns about carbon emissions; and that the much-trumpeted prospective sources of supply, notably LNG from the US and eastern Mediterranean, may simply find no room in the European market.

This approach was kicked off by the veteran gas trader Wolfgang Peters, who blamed the European Union as much as Russia for damaging the reputation of gas as a speedy and cost-effective way of tackling CO2 emissions. “The European Commission will not acknowledge there has been reputational damage to natural gas,” said Peters, who formerly headed RWE’s supply and trading operation in the Czech Republic. “Gas advocacy should be more assertive," Peters said. “Even without a subsidy, it can make a huge contribution to the reduction of greenhouse gas emissions.”

Peters – who at RWE championed the original Southern Gas Corridor project, the Nabucco pipeline, to bring gas from the Caspian to Europe – said the new SGC, operated by Socar, BP and others, would struggle to secure much further input in the near future to enable it to operate at anything like its planned eventual capacity of 31-32bn m³/yr to Turkey and 20bn m³/yr to Italy.

“The elephant has given birth to a mouse,” he said of the $40bn SGC project, which in its first phase is to carry 6bn m³ to Turkey and another 10bn m³/yr towards Italy. Likewise, Cypriot analyst and NGW contributing editor Charles Ellinas doubted that gas from the eastern Mediterranean would reach Europe soon, and wondered whether this was truly appreciated by political leaders in Israel and, especially Cyprus, who hope that their countries will eventually reap rich rewards from gas exports. “The message that the EU is oversupplied and is not interested in eastern Mediterranean gas is not getting there,” said Ellinas.

Much US gas could stay in the US

In the supply context, however, the most striking remarks came from Trevor Sikorski of Energy Aspects. US LNG, he said, may stay in the US. Although US companies have the capacity to export, the actual gas may wind up serving as an option for export, rather than as a mainstay of global trade. The rest of the world may not need it, he argued, and if the Russians and Norwegians keep prices low in Europe, there may be relatively little US LNG coming to Europe. Subsequently conference chairman Stuart Elliot, summing up the first day’s discussions, noted that Russia and Norway were on track to achieve record exports in 2016, “which suggests there may be something like a price war.”

Oil Sands Cost Cutting ‘Close to Bone’ as Crude Recovery Stalls

Canadian oil-sands producers are running out of tricks to buoy their share prices as crude prices keep bumping up against a $50 ceiling.

After two years of slashing costs to cope with plunging oil prices, shares began rebounding as the market appeared to hit a bottom earlier this year. Now, with the commodity recovery taking longer than expected -- even with this week’s agreement by OPEC to limit supply -- and the pace of reductions slowing, a correction could be in store for oil-sands shares.

“We’re getting close to the bone” with cost cutting, said Martin Pelletier, a fund manager at TriVest Wealth Counsel in Calgary, in an interview. He pointed to a “huge gap” between companies’ valuations and the price of oil. Without a solid recovery kicking in soon, companies are "going to go lower."

It’s a lot harder for oil-sands producers to cut costs than it is for their shale-rock drilling brethren. Shale producers can just stop drilling wells, idling rigs and dispensing with all the equipment and labor that goes along with them. Canadian oil-sands companies such as Suncor Energy Inc. and Cenovus Energy Inc., with the massive facilities required to mine and process tar-like bitumen, can’t scale down so easily.

Shale drillers also deploy new technology more regularly, boosting efficiency with each new well. Oil-sands developments take years to plan and build and cost billions of dollars. With the low commodity prices, new projects have been canceled or delayed, hampering companies’ ability to introduce the latest, cost-saving equipment.

That’s left oil-sands producers to rely mainly on slashing operating costs such as labor, non-essential maintenance and spending on garbage trucks and road repairs, to cope with low oil prices in the near term, according to consulting firm Wood Mackenzie Ltd. In the future, new projects will take advantage of technology advances to help reduce capital costs, but that’s an unlikely scenario for the next few years, Pelletier said.

In the meantime, share-price gains are expected to outpace crude in the coming quarters, raising pressure on producers to deliver better profits. The West Texas Intermediate U.S. benchmark oil price is forecast to rise 2.6 percent by the second quarter next year, while the average target price for a Canadian S&P sub-index of Canadian energy companies is expected to gain almost 14 percent, according to analyst estimates compiled by Bloomberg. The price-to-earnings ratio for the 50-member S&P/TSX sub-index has risen to 350 from 98 in the first quarter.

WTI rose 1.7 percent to $47.83 a barrel Thursday, after surging 5.3 percent Wednesday following the Organization of Petroleum Exporting Countries’ agreement to reduce the collective’s production to as low as 32.5 million barrels a day.

Producer Cuts

Oil-sands producer Cenovus will have cut more than C$1 billion in capital, operating and administrative expenses by the end of the year. Since the end of 2014, operating costs have fallen 31 percent at its oil-sands business, helped by laying off almost a third of the company’s work force -- all with the goal of being able to “make money” at $50 a barrel oil, according to Chief Financial Officer Ivor Ruste in a Sept. 7 presentation in New York.

“The question, is are these permanent reductions? Or are they cutting down to the bare bones to just withstand the downturn?” said Stephen Kallir, a research analyst at Wood Mackenzie in Calgary.

By lowering operating expenses, the impact goes “right to the bottom line,” boosting margins for existing operations, said Kevin Birn, director at industry consultants IHS Cera’s energy group in Calgary. “So you’re going through everything and scrutinizing everything you need,” he said.

Companies are also pushing for higher production in a bid to lower per-barrel costs, he said. “We’ve seen more barrels coming from existing facilities than historically they’ve been able to achieve.”

The average cost to produce a barrel of oil, called the lifting cost, for the five largest oil-sands producers has fallen 35 percent since the beginning of 2015, according to data compiled by Bloomberg. At the same time, net debt to earnings before interest, tax, depreciation and amortization has surged three times as profit fell.

Larger competitors Imperial Oil Ltd., Canadian Natural Resources Ltd. and Suncor, also have taken billions of dollars out of their operations.

Cold Lake

Imperial Oil, Exxon Mobil Corp.’s Canadian affiliate, has reduced unit costs by 35 percent since 2014 at the company’s production operations. At its Cold Lake site, costs have fallen 40 percent, helped by lower prices for natural gas and more use of equipment automation, said Bart Cahir, senior vice president of upstream operations.

Overall costs to produce a barrel of oil are now below C$20 “but we know we have much more work to do,” Cahir said during a Sept. 21 presentation.

Suncor has managed to lower oil-sands operating costs in the third quarter to “well below” C$24 a barrel, Chief Executive Officer Steve Williams said in a Sept. 7 presentation to analysts in New York. “Our cash operating costs are in a business which in some cases can last for 50 years.”

Canadian Natural is “confident that there are ongoing opportunities for further cost reductions,” the company said in an e-mail response to questions about whether more cost cuts are possible, without quantifying reductions.

Eventually companies will have to invest in new projects and introduce new, more efficient technology to really capture cost savings, said IHS’s Birn. “You can push operating costs down so far, but you will hit a limit.”

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Much 2017 oil demand growth to bypass refineries: BP

U.S. shale gas will displace a growing portion of the world's expanding energy demand, cutting into the need for oil products from refineries, BP's head of refining economics said on Friday.

Natural gas liquids (NGLs) from the U.S. shale boom such as ethane, an alternative to naphtha refined from crude, could feed as much as a third of demand growth in 2017, BP's Richard de Caux told the Platts Refining Summit in Brussels.

Refined oil products already in storage will further undercut refinery profits, he said.

"We expect a substantial chunk of the incremental demand growth next year to be met by two sources which don't come from a refinery," de Caux said, citing NGLs and oil products in storage.

This week, the first U.S. ethane cargo arrived at a chemicals plant in Scotland, and de Caux said the vessel was a harbinger of supply to come that would undercut profit support for refineries running crude oil, whose margins boomed over the past two years of cheap crude and stellar demand growth.

"That's coming out of oil demand," de Caux said of petrochemicals coming from ethane, rather than from refined naphtha, in petrochemical units.

BP expects demand growth of 1.2-1.4 million barrels per day (bpd) in 2017, of which 300,000-400,000 bpd could come from natural gas liquids. This is up from around 200,000 bpd from as a larger overall demand growth in recent years, de Caux said.

Other consumption growth would be fed by inventories of oil products, which in the developed world stood nearly 150 million barrels above the five-year average in 2016, "close to full," de Caux said.

This is likely to limit refinery margins and runs, putting pressure to close on the continent's refineries, along with aging units in Japan and possibly on the U.S. Atlantic Coast – areas where demand growth is stagnating.

"The cheap oil prices did not save Europe from further rationalizations," he said.

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Colombia's Ecopetrol To Invest $13B Through 2020

Colombia's state-run oil company Ecopetrol will invest $13 billion over the duration of its 2017-2020 investment plan, the company said on Thursday.

The plan, which also includes reducing costs to save up to $700 million, is based on oil prices of $50 a barrel and foresees output of 760,000 barrels per day (bpd), Ecopetrol said in a statement to Colombia's financial regulator.

Were prices to reach between $70 and $80 a barrel, production could climb to 830,000 to 870,000 bpd, the statement said.

Aside from the $700 million in cost reduction, the company is weighing selling off additional assets worth between $700 million and $1 billion.

Spending on production and exploration could reach $11.5 billion over the duration of the plan, and may grow if crude prices improve, the statement said.

The company cut its investment plan this year and has been selling off non-oil related assets in a bid to raise funds and streamline its focus.

China's total 2016 fuel export quotas rise to 46.075 mln tonnes

China has set its fourth-quarter fuel export quota for refiners at a total of 3.47 million tonnes, bringing the year's total to 46.075 million tonnes.

This is more than 80 percent higher than the total volumes of gasoline, diesel, jet kerosene and naphtha China exported in 2015.

Gasoil makes up the bulk of the fourth quarter export quotas at 1.53 million tonnes, followed by gasoline at 1.04 million tonnes. Naphtha and kerosene make up the remaining 900,000 tonnes for the fourth quarter quota.

Trinidad bewails LNG market.

Meanwhile, our oil production has declined drastically, now at 66,000 barrels per day, the lowest in 60 years! And that's not the end of the story. A 2011 audit estimated our oil reserves at approximately 509 million barrels, consisting of 243 million barrels proven, 110 million probable, and 156 million possible, which could be even lower, since risk has not been factored. On the other hand, Rystad Energy has now estimated global reserves at 2.1 trillion barrels, the United States at 264 billion barrels, now with more reserves than Russia at 256 billion and Saudi Arabia 212 billion, other countries with huge reserves being Canada, Iraq, Venezuela and Kuwait. And we must now add Argentina, with the fourth-largest recoverable shale oil resources in the world, 27 billion barrels, expecting to double production from its massive Vaca Muerta fields by 2018. Our reserves are therefore paltry by comparison and with our production down and prices low, it is extremely irresponsible to think of continuing to finance Trinidad and Tobago with proceeds from oil.

And also from gas, where the American shale revolution is turning things topsy-turvy. Having entered the LNG market last January, the US is now selling gas to the Middle East, recently to Dubai and Kuwait, having already shipped to Argentina, Chile, Brazil, India and Portugal. And, just last Tuesday, America sent its first shipment to Britain, opening a “virtual pipeline” across the Atlantic, with the UK and Europe having access to cheap and abundant US shale gas. “We're in a time of huge change in LNG shipping routes,” says Ted Michael of Genscape, a market data provider. “The old order is being overturned, and we haven't seen the dust settle yet”; and Frank Harris, of Wood Mackenzie consultancy says “there is an awful lot of LNG sloshing around the world at the moment, with even more to come, putting downward pressure on prices,” Credit Siusse forecasting depressed prices for the foreseeable future.

So why are we relying on gas? More LNG keeps coming with new projects in Australia and the US, both countries heading to surpass Qatar as the world's largest exporter, “a new train coming on stream every nine weeks,” according to BP chief economist, Spencer Dale. And, as I have pointed out before, with improved technology cutting costs by 40 per cent, LNG production will continue escalating, the US and Canada each having between 100 and 200 years of shale reserves, British Petroleum, in its 2016 Energy Outlook, forecasting US shale growth at four per cent annually from now to 2035, to account for some 20 per cent of global output; BP also predicting China, with the world's largest deposits, will become a major shale oil and gas producer over the next 20 years. Other countries are also now exploring shale, including Poland, Algeria, Colombia, Russia and Mexico, and others from the 41 countries with impressive reserves. Spencer Dale says the “shale revolution is here to stay and by 2035, will be responsible for half the gas supply worldwide”.

Alternative Energy

In contrasting strategy, China to ramp up REE output to regain pricing control

The Chinese government is expected to ramp up rare earth element (REE) exports in a bid to regain control over pricing policy, according to a new report by market intelligence firm BMI Research.

This is expected to be a reversal from the government's previous export-restrictive strategy to control prices.

Rare earth metals are critical raw materials, used in a diverse number of sectors, including the electronics,telecommunications and automotive sectors.

Over the last two decades, China has maintained a virtual monopoly on REE output. According to BMI, China's share of global rare earth output accelerated rapidly from 1999 to 2015. In 2015, China's REE output totalled 105 000, accounting for over 90% of global output, with other countries accounting for just 19 000 t during this period.

PREVIOUS POLICIES

Between 1990 and 2015, China's policy by default of ramping up rare earth output developed later into a deliberate policy of increased REE pricing power. Between 1990 and 2000,China's rare earth output grew by 450% to 73 000 t. Over this same period, rare earth output from other countries (Australia, US, Greenland, Malaysia and Brazil) declined by 60% to 16 000 t, down from 44 000 t in 1990. The latter countries' decline was largely the result of decreasing margins on the back of an increasingly well-supplied market, researchers noted.

In 2006, China shocked the world when it suddenly imposedexport quotas and duties for REE exports and, in 2010, the Chinese government decided to reduce the country's REEexport quota by 40%, which saw rare earth prices soar globally. The government stated that the 2006 quota was to conserve the country's environment and limit the depletion of critical resources.

Despite more than 28 World Trade Organisation (WTO) members imposing export restrictions on certain metals and minerals during the previous decade, BMI found that there was some international concern that China's control of the rare earth market and restrictions on exports could be used as a political weapon.

Subsequently, the US, joined by the European Union andJapan, brought a case to the WTO's dispute settlement body against the Chinese REE export restrictions in 2012. China's case was brought forward to the WTO, which ruled against the policy in 2014.

On January 1, 2015, after losing its battle in the WTO's final ruling, China ended the country's 16-year-old REE exportquota system and, on May 1 last year, eliminated exporttariffs on REEs, including tungsten, molybdenum, iron andsteel particles, as well as other products, as part of the ruling 's requirement.

This resulted in China losing rare earth production market share to other producing countries, including the US,Greenland and Russia, BMI stated.

NEW WTO CASE?

BMI expects that, in a bid to regain pricing power, the Chinese government will pursue a strategy of consolidating the country's domestic rare earth sector and increasing exports over the coming quarters.

“We believe the Chinese government will pursue a strategy of increasing supply in order to push down prices, which will put pressure on overseas miners' profit margins," said the firm.

Since the export tariffs were removed, Chinese rare earth exports have consistently been higher than during the period beforehand, BMI noted.

The strategy has resulted in rare earth prices falling drastically over the last 18 months. Over 2015, export prices from China's Inner Mongolia region fell by 30% compared with 2014, while China's total export value of rare earths decreased by over 40% over the same period.

Among the hardest hit have been dysprosium and cerium, which saw prices fall from $65 865/t and $883/t respectively, in May 2015, to $37524/t and $685/t respectively, by September 2016.

While domestically this has accelerated the government's consolidation drive, it also proved a major challenge for producers operating in countries such as Australia and the US. The most notable example occurred on June 25, 2015, when US-based REE producer Molycorp filed for Chapter 11 bankruptcy.

While the firm had been operating with losses since 2011, the low-price environment exacerbated its struggles. Molycorpwas able to previously maintain operations as it was deemed a key alternative supply channel for the US, other than China.

In light of China's new approach, BMI expects another trade case to be presented to the WTO by the US and other major rare earth consumers over the coming quarters.

BMI believes that Australia, Russia, Greenland and the US hold significant rare earth output growth potential over the long term. Despite this, the analysts do not expect that these countries will be able to overtake China's market share any time soon, owing to China's strategy, which has resulted in the current low rare earth price climate.

U.S. plans to stockpile more lithium compounds used in batteries

The U.S. Defense Logistics Agency (DLA) said it has a mandate to buy 600 kg of lithium cobalt oxide (LCO) and 2,160 kg of lithium nickel cobalt aluminium oxide (NCA) in the fiscal year starting Oct. 1.

The amounts were detailed by the DLA in its Annual Materials Plan for financial year 2016-2017, which runs from October to September, published on its website this week.

They are double the 300 kg of LCO and 1,080 kg of NCA it was mandated to buy in the 2015-2016 fiscal year.

Both compounds are used to make lithium-ion batteries. LCO batteries are used for mobile phones and laptops and NCA batteries are used for electric vehicles.

In 2014 the DLA was authorised for the first time in 20 years to acquire new materials for the National Defense Stockpile (NDS). It has authorisation to buy cobalt compounds from fiscal year 2014 through fiscal year 2019.

Under the Defense Production Act of 1950, the U.S. Geological Survey advises the DLA on the acquisition and disposal of NDS mineral materials.

South Aus electricity outage: wind to blame?

UK solar beats coal over half a year

The UK’s solar panels generated more electricity than coal across the past six months combined, Carbon Brief analysis shows, rounding off a historic half-year of firsts.

Saturday 9 April 2016 was the first-ever day where more electricity was generated in the UK by solar than by coal. May 2016 was the first-ever month. The three months from June through to September was the first-ever quarter. And now the six months to September is the first half year.

These firsts reflect the changing face of UK electricity supplies, with solar capacity having nearly doubled during 2015. They also reflect historic lows for coal-fired generation, driven by changes in wholesale energy markets and the carbon price floor. Carbon Brief runs through the numbers.

Solar six months

The UK’s solar panels generated an estimated 6,964 gigawatt hours (GWh) of electricity during quarter two (Q2) and three (Q3) of 2016, from April through to September. (See note below regarding data sources and methodology).

The solar output was equivalent to 5.2% of UK electricity demand for the half-year period. It was nearly 10% higher than the 6,342 GWh generated by coal, which covered 4.7% of demand.

Shares of total UK monthly electricity generation met by solar and coal during 2016 (%). Sources: Sheffield Solar and Gridwatch.

Starting on 1 July, there were 10 straight weeks when solar output exceeded that from coal.

Solar output is strongly affected by the UK’s seasonal cycle. Roughly three-quarters of annual UK solar power is generated during the sunnier half-year from April to September. In contrast, coal generation tends to increase in winter when electricity demand peaks.

First, UK solar capacity has to date reached around 12 gigawatts (GW), according to research by Solar Intelligence, up from around 6GW at the start of 2015. Solar generation is increasing as a result, up 26% in 2016 to date, compared to the same period in 2015.

(Note that solar capacity additions have fallen this year, following subsidy cuts. Note also that while government figures for new capacity have been consistently too low, independent estimates also show the drop.)

Total electricity generation from UK solar and coal during calendar months in 2015 and 2016 to date, gigawatt hours (GWh). Sources: Sheffield Solar and Gridwatch. Chart by Carbon Brief using Highcharts.

Coal generation has fallen rapidly, at a rate that is far beyond its usual annual cycle. Output in 2016 to date was 65% below that in 2015. It was down 76% in Q2 and 82% in Q3 compared to a year earlier.

This year also saw UK coal generation fall to zero on 9 April, for the first time since 1882, when a coal-fired power station started supplying electricity to the public for the first time. Since then, there have been 199 hours when coal was generating no power in the UK.

The drop in coal output has come about because of wholesale energy market price shifts being more favourable to gas-fired generators than to coal. In addition, the UK’s carbon floor price doubled in April 2015, again shifting the economics of electricity generation in favour of gas over coal.

Given these price changes, and the government’s stated intention to phase out all unabated coal by 2025, three coal-fired power stations took the decision to close this spring.

The key role of the carbon floor price in driving coal off the system is underlined in recent analysis from consultancy Cornwall Energy. This shows that removing the UK’s top-up carbon tax would mean coal plants once again being cheaper to run than gas.

Tom Edwards, Cornwall Energy senior consultant writes:

“This would return the market to the position seen in 2014 when coal-fired generators were running baseload [all the time] and gas-fired stations were pushed to the margin.”

It’s worth noting that while gas-fired power stations have replaced most of the reduction in coal output, the total supplied by the two fossil fuels is also falling. This is because of increases in electricity supplied by renewables and imports, along with falling demand.

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Solar business rates may hammer UK supermarkets?

Valuations Office acts to limit business rates for companies exporting sizeable amount of solar power to the grid, but those using power on site could yet see eight-fold tax increase

The solar industry appears to have won a partial victory in its push to ensure companies, schools and hospitals that have installed solar arrays are not hit with a huge tax hike next year, although fears remain many organisations could still see business rates for their solar installations increase six to eight fold.

The Valuations Office Agency (VOA) is today expected to confirm that organisations that 'mainly export' their solar power will see a decrease in business rates to reflect the falling cost of solar technologies and recent cuts to subsidies.

The cuts will apply to organisations that export over 50 per cent of the power they generate, either by supplying power to the grid or by selling it to the organisation hosting the array through a Power Purchase Agreement (PPA).

The approach follows the signing of a Memorandum of Agreement between the VOA and the Solar Trade Association (STA), which has been leading the campaign to ensure companies that have installed solar arrays are not hit by sharp increases in business rates next year.

"The good news for 'export' solar is that, in most cases, the rateable value will fall from 2017, some by as much as half," said Paul Barwell, chief executive of the STA in a statement. "Rates should reflect the true value of the solar asset, as well as the income received. As both of these have fallen dramatically over the last five years for solar power, the rateable value has also fallen: logic has prevailed."

However, the trade body remains concerned organisations which use the bulk of the solar power they generate directly on site are still on track to face a six to eight fold increase in the business rates they have previously paid for solar, despite consuming power onsite being a highly efficient option.

Moreover, industry insiders are concerned the promise of cuts in business rates for solar arrays that have a PPA in place means two identical arrays would be taxed differently based on the legal ownership structure for the solar installation.

The discrepancy raises the prospect of companies or schools setting up a Special Purpose Vehicle (SPV) to take ownership of a solar array and sell the power back to themselves through a PPA in order to take advantage of the lower business rates.

Business and Energy Minister Jesse Norman said recently the government would "look at it closely" at the situation when the VOA comes forward with its plans for valuing solar arrays.

Sion Power announces the achievement of highly pursued next generation battery performance with its patented Licerion® technology. Licerion® is the registered trademark for newly developed battery products designed to meet specific market needs, including unmanned aerial vehicle (UAV) and electric vehicle (EV) markets.

Sion Power’s Licerion®-Sulfur products are being commercialized via its partnership with Airbus Defence and Space. An earlier version of the technology was employed in setting a world record for the longest duration unrefueled flight for a high altitude pseudo-satellite (HAPS).

Based on Sion Power’s 20 Ahr cell design, Sion Power’s Licerion®-Ion system has achieved 400 Wh/kg, 700 Wh/L and 350 cycles under 1C discharge conditions. Details of this remarkable achievement will be presented by Dr. Yuriy Mikhaylik, Sion Power’s Director of Materials, at the upcoming ECS meeting in Honolulu, October 2-7, 2016.

Sion Power is in the process of expanding its facilities in Tucson, Ariz. for the production of prototype large format Licerion® Ion cells. These cells will be available by December 2017. In the interim, Sion Power is evaluating potential volume manufacturing partners to supplement in-house capacities.

About Sion Power:

Privately held Sion Power Corporation is the global leader in the development of next generation high-energy, rechargeable lithium batteries for UAV, military and electric vehicle applications. Sion Power has assembled a world class team dedicated to advancing lithium battery technology. The company has more than 170 U.S. and international patents, and is headquartered in Tucson, Ariz. Further information is available at www.sionpower.com.

Attached Files

Energy investment boom expected in northern Chile

Investment in Chile’s energy industry is expected to jump over the next five years to as much as $3 billion, which could add about 2.5% to the country’s potential GDP growth, US-based Trade Commissioner Rodrigo Mladinić said.

Speaking at a media briefing during MINExpo 2016 this week, Rodrigo Mladinić said that projects, many of them in the renewables sector, are expected to also boost machinery acquisitions and generate close to 3,000 new jobs.

The projects, many of them in the renewables sector, are expected to boost machinery acquisitions and generate close to 3,000 new jobs.

The trade officer noted that Chile’s rising energy demand, pushed by a booming mining production and economic growth in the past 10 years, has already triggered triggered the creation of 29 solar farms supplying the central grid, with another 15 planned.

In the north of the country, which is where most copper operations are located, even more have been built, Mladinić said.

While prices for copper, Chile’s main export, remain subdued, the officer said there are strong signs in the market that suggest the red metal will begin rising by mid 2018. The timing coincides with what industry players such as Antofagasta (LON:ANTO) expect the metal to start swinging back into deficit amid a lack of new projects and as Chinese demand continues to grow.

There already are encouraging signs, such as this week’s move by Teck Resources, Canada’s largest diversified miner, requesting environmental approval for a revised expansion project at its Quebrada Blanca copper mine in northern Chile.

Mladinić noted that projects like that one are expected to push demand for engineering services in the mining sector to over $36 billion by 2020.

A similar figure is estimated for sectors other than mining. Construction work and equipment related to engineering companies may represent a further $29.7 billion. Engineering for closure plans, in turn, may reach $20 million per project, the executive said.

Tesla Motors Inc said on Sunday its third-quarter deliveries rose 70 percent to 24,500 cars, following production improvements, cheaper lease deals and reports of discounts on some vehicles.

Deliveries are a key metric of performance for the luxury electric vehicle manufacturer, which had missed these targets in the previous two quarters.

The improved deliveries for the third quarter bring Tesla closer to meeting its second-half 2016 target of 50,000 vehicles, which it reiterated on Sunday. It said in a statement that fourth-quarter deliveries would be "at or slightly above" the third quarter's.

However, the third-quarter figures included 5,150 vehicles in transit at the end of the second quarter, as Tesla reported in July. Another 5,500 cars in transit would be counted in the fourth quarter, it said.

Meeting the third-quarter target was a priority for the money-losing Silicon Valley carmaker, which is hoping to raise funds from the equity market later this year for multiple efforts, including building out its factory for the Model 3 mass-market sedan due in late 2017 and the planned acquisition of SolarCity Corp (SCTY.O).

Tesla experienced production problems earlier this year and began to resolve them in June. It said in July that production would improve from 2,000 cars a week to 2,200 in the third quarter and 2,400 in the fourth.

Production rose in the third quarter to 25,185 vehicles, implying just shy of 2,000 vehicles per week.

The company will release third-quarter financial results in early November.

Chief Financial Officer Jason Wheeler said in August that if second-half production and delivery targets are met, the company had a "great chance of being non-GAAP profitable," without specifying a time period.

In September, Tesla began advertising its inventory cars, for showrooms or test drives, "at favorable prices and ready for expedited delivery."

Last week, Chief Executive Officer Elon Musk published a memo telling employees to follow the company's policy of not offering discounts on new cars.

Musk was responding to a research note published on Tuesday by Pacific Crest Securities analyst Brad Erickson criticizing Tesla for offering discounts on Model S inventory cars, not those built-to-order for specific customers, to boost third-quarter sales.

Uranium

Tepco looks for government aid amid fears of bankruptcy

The President of Tokyo Electric Power Co Holdings (Tepco) has requested what he referred to as ‘structural assistance’ in helping the company decommission the ill-fated Fukushima Daiichi nuclear reactor power plant.

Naomi Hirose says his company does not want financial assistance but is in need of a plan to avoid the firm avoiding bankruptcy in dismantling the reactors. Fukushima had provided one third of Japan’s electricity prior to a 2011 accident caused by a tsunami impacting on the plant leading to reactor melt down.

"We don't want to receive national rescue measures but want to bear the Fukushima responsibility ourselves," Hirose told a government panel. "For that reason, we would like to undertake steps for a further overhaul than we have had so far."

Five and a half years on, Tepco still struggles to contain radioactive water from the plant and has said it can't predict the eventual costs of clean-up and decommissioning. According to Zero Hedge website, the reactors “continue to leak around 300 tonnes of radioactive waste into the Pacific Ocean every day.

That is set to continue ” as the source of the leak cannot be sealed as it is inaccessible to both humans and robots due to extremely high temperatures.

Hirose told reporters that it is difficult to accurately predict the costs of even a gradual decommissioning of the crippled reactors.

"If the issue of recognising all the estimated losses at once were to emerge, our company would fail, so we would like some structural assistance from the government to be able to avoid that risk," Hirose said.

French day-ahead spot power price jumps on further outages

The was also another unplanned outage at Engie's 428 MW gas-fired plant, French grid operator RTE said on its website.

European power prices have hit one year highs in the past week on French nuclear power supply concerns. According to Reuters tabulation, 22 out of 58 French nuclear reactors are currently on planned or statutory outage.

Attached Files

Cameco to court over tax bill

Canada’s biggest uranium producer, Cameco, is set to appear in court on Wednesday to dispute accusations of setting up a subsidiary in Zug, Switzerland for the purpose of avoiding taxes.

Canada Revenue Agency contends whether the Saskatoon-based corporation wanted to dodge its fiscal duties by signing a 17-year agreement in 1999 with its Swiss arm to sell uranium at the fixed price of about US$10 per pound.

The practice is seen as ‘unfair’ given that the price of uranium rose to over US$130 a pound by 2007 and, despite the fact it has been in a steep downward trend ever since, still trades at over US$20 a pound today.

According to the CBC, the CRA is looking to shift an estimated $7.4 billion in foreign earnings between 2003 and 2015 back to Canada.

The current case, which has been moving slowly through appeals and legal motions since 2009, is dealing specifically with tax years 2003, 2005 and 2006. But the company has always said that its management had a compelling business case for having a marketing arm in Europe.

Back in 2013, Cameco’s CFO Gran Isaac told investors: "We believe that it was established in accordance with sound business principles and in accordance with relevant laws and regulations."

Meanwhile, Cameco spokesman Gord Struthers repeated the statement in a recent email to theCanadian Press: "We followed all of the rules and paid all taxes owed under Canadian law. There is a sound business rationale for Cameco's corporate structure and related transfer pricing arrangements and we remain confident that our position will be upheld by the court."

The world's number one listed uranium producer doesn't expect the actual trial to wrap up until March 2017, with a ruling six to 18 months after that.

Agriculture

Vale fertilizer deal on track despite BNDES delay -sources

Vale SA's plan to dispose of fertilizer assets remains on track despite a request last week by Brazil's state development bank, BNDES, to analyze the transaction more carefully, according to two people with direct knowledge of the situation.

Terms of the deal, which involves the sale of certain assets to U.S.-based Mosaic Co, are unlikely to change significantly, one of the sources said on Wednesday, requesting anonymity to speak freely about the issue.

BNDES pushed back the vote on the fertilizer deal at a Vale board meeting last Thursday, the first person familiar with the situation said. O Globo columnist Lauro Jardim, without saying how the newspaper obtained the information, reported that day that BNDES had delayed the voting on the transaction to Oct. 20.

One of the people said Mosaic could pay about $3.6 billion for some of Vale's fertilizer assets. The sale of other unspecified operations within Vale's fertilizer unit is being negotiated with Norway's Yara International ASA, the first person said, without elaborating.

Both Vale and BNDES, which are based in Rio de Janeiro, declined to comment, as did Mosaic. Yara said it did not comment on market speculation.

Vale, the world's largest iron ore producer, is disposing of assets to help meet a $10 billion debt-reduction target by next year. The strategy was devised by Chief Executive Officer Murilo Ferreira to help insulate the mining company against declining iron ore and nickel prices, after losing a record $12.1 billion last year.

Reuters first reported on June 17 that Mosaic was eyeing Vale's fertilizer assets.

The transaction underscores how Brazil, the world's fifth-largest fertilizer consumer, remains a key growth spot for fertilizer and phosphate producers. Vale estimates that demand for the products in Latin America's largest economy is expected to grow twice as fast as global demand over the next decade.

Monsanto surprises with adjusted profit as expenses drop

U.S. seeds and agrochemicals company Monsanto Co (MON.N), which agreed last month to be bought by Germany's Bayer AG for $66 billion, reported a surprise adjusted profit, helped by a drop in expenses and higher corn seed volumes.

Monsanto agreed in September to a sweetened $128-per-share offer from Bayer that, if approved by regulators, would create a company commanding more than a quarter of the world market for seeds and pesticides.

The St. Louis, Missouri-based company had been expected to report a loss on an adjusted basis, reflecting a slump in commodity prices and a fall in farm incomes.

However, net sales in the company's corn seeds and traits business jumped 34 percent in the three months ended Aug. 31 as corn seed volumes rose in the United States.

Monsanto's expenses also dropped, by nearly 10 percent, as its cost cutting measures paid off. The company said in January it would cut about 3,600 job cuts, or about 16 percent of its global workforce, through fiscal 2018.

The company's global restructuring also includes an exit from the sugar cane business and streamlining some commercial and research and development work, the company has said.

Monsanto, whose shares were little changed in premarket trading on Wednesday, did not offer any update on potential divestitures related to the Bayer deal.

Some farm groups, rival seed companies and lawmakers have raised concerns about the huge deal, saying it could result in higher prices and reduced choices for farmers.

Bayer and Monsanto have said they are confident that the deal will pass regulatory muster. Bayer has said it is committed to divest up to $1.6 billion of its portfolio to win approval.

The net loss attributable to Monsanto narrowed to $191 million, or 44 cents per share, in the fourth quarter ended Aug. 31 from $495 million, or $1.06 per share, a year earlier.

Excluding items, however, the company earned 7 cents per share. Analysts had expected a loss of 3 cents per share on that basis, according to Thomson Reuters I/B/E/S.

Net sales of the company, known for its genetically engineered corn, soybean and the Roundup herbicide, rose 8.8 percent to $2.56 billion, beating the average estimate of $2.36 billion.

Up to Tuesday's close of $102.15, Monsanto's shares had fallen about 4.3 percent since the Bayer deal was announced last month.

The latest chapter in the glyphosate wars began to unfold on Sept. 28 when a group of toxicology experts published a paper in Critical Reviews in Toxicology. The Expert Panels paper examined the International Agency for Research on Cancer’s assessment of glyphosate.

At last count more than 160 countries have approved uses of glyphosate-based herbicide products. According to most scientists, the active ingredient in Roundup and other herbicides is a relatively benign product as pesticides go.

So why has glyphosate become the pesticide environmental activists love to hate? One reason: It was developed by Monsanto, the company often referred to as the “Great Satan” when activists are lashing out at what they call “industrial agriculture.”

(If you want to see just how absurd the attacks on Monsanto have become, click on this website http://www.monsanto-tribunal.org/. It’s the website for a group of organizations that are planning to “hold Monsanto accountable for human rights violations, for crimes against humanity and ecocide” in a tribunal that is scheduled in the Hague, Netherlands, Oct. 14-16.)

The latest chapter in the glyphosate wars began to unfold on Sept. 28 when a group of toxicology experts published a paper in Critical Reviews in Toxicology. The Expert Panels paper examined the International Agency for Research on Cancer’s assessment of glyphosate.

Basically, the experts said a monograph the IARC published in March of 2015 concluding that glyphosate is “probably carcinogenic to humans,” is a bunch of nonsense.

Yes, the panel’s review of the IARC monograph was financed by Monsanto, but, unlike the authors of the IARC document, the panel was made up of actual scientists with reputations for scholarly work to protect.

So why bother? “Every day I read an article from an activist-captured media source that quotes the IARC glyphosate position and ignores the negative reactions from institutions such as the European Food Safety Authority,” said one blogger who writes frequently about the pesticide debate.

“It would be nice if we could ignore IARC’s erroneous excursions into anti-industry activism, but the NGO campaigners and organic food lobbyists have sanctified their glyphosate monograph to Biblical proportions. They are regularly attacking the scientific establishment in their campaign to ban glyphosate.”

Glyphosate isn’t the only pesticide being targeted by activists, who seem convinced we can feed 8 billion people with organically grown crops. But it’s becoming the lightning rod in a fight society must win if the world’s farmers are to continue feeding and clothing its population.

Precious Metals

The world's largest gold project, just got a whole lot bigger

During the final days of 2014 Canada's minister of the environment gave the green light to Seabridge Gold's KSM project in northern British Columbia, the world's largest undeveloped gold-copper project by reserves.

The federal and provincial environmental assessment process took nearly seven-years and KSM was only the second metal mine in five years to receive approval.

A new preliminary economic impact study released by Toronto-based Seabridge on Thursday, the already ambitious project takes another leap forward.

During the first seven years of operation annual gold output would top 1 million ounces

According to a statement, Seabridge now envisages a much larger operation than the one outlined in the preliminary feasibility study released last month and in the process improves both the environmental impact and economics of KSM.

The PEA calls for mill throughput of 170,000 tonnes per day, 40,000 tonnes more than the earlier study which Seabridge says can be done without significant redesign of facilities. Initial capital costs have been increased by just less than 10% to $5.5 billion.

In the PEA the bulk of the operations are moved underground and using the block-cave method Seabridge says it can reduce waste rock by a whopping 81% or 2.4 billion tonnes over the 51 year life of the mine.

By vastly increasing the amount of copper mined life of mine operating costs are now a negative $179 an ounce while all-in costs fall to just $358 an ounce.

Measured and Indicated Mineral Resources at KSM are estimated at 2.9 billion tonnes grading 0.54 grams per tonne gold, 0.21% copper and 2.7 grams per tonne silver which translates into 49.8 million ounces of gold, 13.6 billion pounds of copper and 253 million ounces of silver.

During the first seven years of operation annual gold output would top 1 million ounces and life of mine annual production is estimated at 592,000 ounces of gold, 286,000 pounds of copper and 2.8 million ounces of silver.

Attached Files

AMCU says platinum wage talks at a critical stage

Wage talks are at a "critical stage" between South Africa's Association of Mineworkers and Construction Union (AMCU) and Anglo American Platinum, Impala Platinum and Lonmin, the union's president said on Thursday.

Speaking to journalists on the sidelines of a mining conference, Joseph Mathunjwa would not say if AMCU had moved from its original demands of close to 50% pay hike. Amplats' chief executive said on Wednesday that his company was "fairly close" to sealing a wage agreement with AMCU and other unions.

Fund managers, analysts weigh political risk in SA mining

The undue influence of politics on South African mining was highlighted by fund managers and analysts at the Joburg Indaba today, but Allan Gray portfolio manager, Sandy McGregor, stressed the most important aspect of a decision to invest in mining was the orebody.

Taking part in panel discussions, the fund managers and analysts also emphasised investors had a choice between mining and non-mining shares. Non-mining shares were being more favourably viewed because of the meltdown in mining shares over the past three years.

According to Fiona Perrott-Humphrey, senior adviser to the mining team at Rothschild, London: “The London view is that optimal capital allocation in mining is an oxymoron. Their view is that miners should get real with themselves and the first sector to get real has been gold. Investors now want to see the rest of the mining industry perform.”

Stephen Arthur, head of equity; asset management at ABSA Asset Management commented: “My decision every day is: do I buy Shoprite or do I buy a South African mining share? I learnt a new buzzword the other day – optics – and the optics on Shoprite are far better than the optics on a South African mining company.

“You have all these legislation and political issues that take up management time with very little management time being spent on actually running the mining operations. One mine manager told me he spent up to 70% of his time on community issues.

“That’s not good enough for me and I think the reason the majors have moved out of South Africa is because there’s too much hassle – too much noise. We need to eliminate the noise and get back to mining.

“I know PicknPay [South African retail business] will be open 365 days a year. I cannot say with certainty how many days a mine will be able to operate each year because of issues like Section 54 safety shutdowns.”

Perrot-Humphrey added: “There is a perception in London that that capital allocation in the South African mining industry is being affected by political decisions. They would like to see pure supply and demand issues driving capital allocation.”

“Mining has been going on in South Africa for 130 years and the number of great deposits remaining is relatively few. There are some really great deposits in the Congo.

“There’s a small problem with the country but, in the long term, the mining business is likely to be in the Congo because that’s where the deposits are. A great deposit can make a lot of money for shareholders.”

Arthur pointed out the “biggest slug” of the financial benefits from mining actually went to government with shareholders only getting 9% of the benefits.

“What I cannot believe is that government is not bending over backwards to promote the mining industry and get things working properly,” he said.

Arthur’s comments were built on by Cadiz Corporate Solutions mining consultant Peter Major who said: “It’s the environment here which is so anti-mining. You keep thinking government cannot miss all the benefits of mining but they have; month after month, and year after year.

“We have a government that is totally oblivious. Every one of the 2,000 pieces of legislation makes mining harder and harder. If that’s not fixed nobody has any reason to invest here,” he said.

Talks to resolve Goldcorp Mexico mine blockade under way: official

Negotiations are under way to resolve a week-long blockade at Goldcorp Inc's suspended Peñasquito gold mine in Mexico, a government mediator said on Wednesday.

Goldcorp, the world's No. 3 gold miner by market value, said on Monday that it shut mine operations on safety concerns from the blockade by a trucking contractor concerned about losing business due to mine efficiencies.

Talks began Tuesday night and another meeting was scheduled for Wednesday, said Julio Cesar Chavez, a Zacatecas government official and mediator in talks between Goldcorp and the trucking contractor and farmers, who have joined in the protests against Goldcorp.

"An agreement with the land owners and a trade agreement with the truckers is pending today," he said in an interview with Reuters.

Vancouver-based Goldcorp was not immediately available for comment.

There are 420 police officers at the site and they have cleared three entrances to the mine, Chavez said. One truck brought food into the mine yesterday, and protesters are now being asked to allow another truck to enter with water, he said.

In a meeting Tuesday night, truckers and a committee representing farmers asked Goldcorp to withdraw lawsuits against protesters, said Felipe Pinedo, one of the protest leaders.

Protesters are demanding jobs and payment for environmental damages and water used by the mine, Pinedo has said.

In late August, Reuters reported on a long-running leak of contaminated water, which had not been disclosed to the public, at the mine, Mexico's biggest gold deposit.

Goldcorp said it has about 750 people at the northern Mexico mine and expects to produce between 520,000 and 580,000 ounces of gold this year, equal to around 19 percent of its total forecast output of 2.8 million to 3.1 million ounces.

A contingency plan was in place that would allow mining and processing to be restarted immediately once the dispute was resolved, Goldcorp said. It did not expect the shutdown to impact 2016 production or cost estimates.

Erdene Resource Development Corp. is pleased to announce results from the first seven holes of its originally planned 5,000 metre drill program at its 100%-owned, high-grade Bayan Khundii gold project ("Bayan Khundii") in southwest Mongolia. In addition, the Company announces an expanded drill program with a total of 9,000 metres now anticipated to be completed in Q3-Q4 at Bayan Khundii and at the Company's neighbouring, 100%-owned Altan Nar and Altan Arrow gold projects. Included with this release, for reference, are two plan maps and a cross-section showing project locations, the position of today's drill holes, as well as areas where drill results are pending.

"Bayan Khundii continues to deliver exceptional, near-surface gold grades over wide intervals and today's results increase our confidence in the continuity of these gold zones and the broad extent of the lower-grade mineralization," said Peter Akerley, Erdene's President and CEO. "As the drill program advances we will be testing multiple targets outside of the known mineralized area, predominantly under younger cover rocks, to better establish the size potential of the Bayan Khundii gold system."

Attached Files

De Beers rakes in $485m from diamond sales

Diamond producer De Beers has raised $485-million from its eighth sales cycle during the year.

CEO Bruce Cleaver said on Tuesday that the demand for its rough diamonds continued to reflect the improved midstream trading environment compared with 2015.

“Our rough diamond sales were slightly ahead of expectation during the cycle, given the normal seasonal demand patterns, the shorter-than-usual period between sights 7 and 8, and the forthcoming holidays in some of the major diamond cuttingcentres,” he noted.

South Africa's Sibanye Gold shuts mine after union violence

Work at Sibanye Gold's South African Cooke mine has been suspended after two members of the National Union of Mineworkers were left in a critical condition after being attacked, a spokesman for the company said on Tuesday.

"We cannot have the mines operating when we cannot guarantee the safety of our workers. No one went underground last night and no shifts began this morning," Sibanye spokesman James Wellsted said.

NUM spokesman Livhuwani Mammburu said the miners were attacked by members of the rival Association of Mineworkers and Construction Union in a dispute over union numbers. AMCU officials could not immediately be reached for comment.

The incident is the latest flare-up between the unions. The arch rivals have been locked in a turf war which has killed dozens since AMCU dislodged NUM as the dominant union on South Africa's platinum belt in 2012.

In the first half of 2016, the three working shafts at Cooke produced around 100,000 ounces of gold, about 13.5 percent of the group's total gold production.

Implats, NUM sign two-year wage deal

The National Union of Mine workers (NUM) and Impala Platinum (Implats) have reached a two-year wage deal, effective July 2016 until June 2018, for workers at Implats' refinery operation, in Springs.

The 1 000 workers at the operation, of which about half are NUM members, will now see a basic wage increase of 7.5% to 10% over the two-year agreed period.

“The NUM elected to initiate industrial action on Tuesday last week, and we ultimately concluded the wage agreement on Friday evening,” Implats spokesperson Johan Theron said.

Entry level B-lower and B-upper employees will receive a 10% hike a year, while B5 workers will receive an 8.5% increase backdated to July 2016 and again in July 2017.

The B7 and C-lower workers will receive a 8% hike in the first year starting July 2016 and a 7.5% increase in 2017.

Medical subsidies will also increase from the current R490 to R524 in 2016 and R561 in 2017, with subsidies increasing to R377 and R228 respectively for the first dependant and other dependants by 2017.

Accommodation allowances have also increased, with B-lower and B-upper workers receiving a R2 460 allowance, up from the current R2 365, before increasing to R2 632 in 2017.

B5 and B7 workers get an increase from R2 870 to R2 985 in 2016 and to R3 194 in 2017, while C-lower workers will not receive an increase on the current R5 343 allowance in 2016, but will receive an increase to R5 557 in 2017.

The parties also agreed that the four-shift cycle shift allowance will increase from the current 13% to 13.5%.

“NUM members at Impala Platinum Refineries are quite pleased and excited that the wage agreement was concluded without any strike, violence, intimidation and loss of life,” NUM said in a statement.

“We are pleased to have secured a negotiated settlement following the industrial action last week. The wage agreement, in our opinion, provides a reasonable compromise between worker expectations, wage inflation in our economy and the economic realities that dictate the financial sustainability of our business,” the company said on Monday.

Goldcorp starts controlled shutdown of operations at a Mexico mine

Canada's Goldcorp Inc said it was undertaking a controlled shutdown of operations at its Peñasquito gold mine in northern Mexico, following a blockade by a trucking contractor that began on last Monday.

Goldcorp said on Monday the contractor was concerned about losing business after the company's recent efforts to diversify its local transportation supply chain.

The company said it had taken legal steps, including filing criminal charges against the protesters. The company also said it was ready to talk with the contractor's representatives.

The world's third-biggest gold producer by market value said it did not expect the shutdown to impact overall production or cost estimate for 2016.

Argentina judge rules Barrick mine to remain suspended

A judge in Argentina ruled that Barrick Gold Corp's operations at its Veladero mine would remain suspended, saying repairs were insufficient to reopen it after a leak of processing solution containing cyanide earlier this month.

Judge Pablo Oritja's decision was based on a report from mining police in San Juan province that found Barrick had not installed security cameras and sensors as required, state news agency Telam said on Friday.

A spokesman for the province said Oritja had extended the temporary suspension of operations on Thursday until Barrick completes additional work at Veladero, one of its five core mines.

Barrick President Kelvin Dushnisky told Reuters on Sept. 19 that he thought the mine could start operating again in two weeks.

Toronto-based Barrick said on Friday that it had completed "critical" work required by authorities for the resumption of operations and was awaiting a final resolution of the matter.

The world's largest gold producer by output, Barrick does not expect the suspension to cause it to miss its 2016 consolidated production forecast, said spokesman Andy Lloyd.

Barrick said provincial regulators ordered work in seven areas, including maintenance of the exterior perimeter of the leach pad liner and raising the exterior berm, or bank, over which the processing solution flowed.

The company gave no estimate of the costs of the work or suspension. It will finalize them once the mine is back in operation, Lloyd said.

Telam said Oritja would go on vacation on Friday, meaning another judge could handle the case.

Barrick has not said how much processing solution was spilled. Tests by United Nations investigators in October showed the year-earlier spill had not contaminated local water supplies.

The company announced the spill on Sept. 15. The province had fined Barrick nearly $10 million for a September 2015 leak.

Attached Files

Base Metals

Rio CEO says Mongolia won’t receive mine dividend for ten years

Rio Tinto Group said Mongoliawon’t receive any dividend from the giantOyu Tolgoi mine for ten years as the world’s second-biggest mining company prioritizes completing a $5.3-billion underground expansion.

Oyu Tolgoi, which at its peak will be one of the top five coppermines in the world, is partly owned by the government andTurquoise Hill Resources , which is majority controlled by Rio. In the past, Rio has said the project, the biggest in the country’s mining history, could account for about one-third of Mongolia’s gross domestic product.

“We shouldn’t forget that Oyu Tolgoi is a long-term project,”Jean-Sebastien Jacques, Rio’s CEO said in an interview with Bloomberg Television Mongolia in Ulaanbaatar on Thursday. “It will take us five years to build the infrastructureand seven to nine years to ramp it up.”

“Until we get to a steady state, which is clearly ten years down the road, we will not pay a dividend to anybody,” he said.

Rio reported net earnings of $53-million from Oyu Tolgoi in the first half of this year. Mongolia owes Turquoise Hill about $1-billion, Jacques said.

Rio and Mongolia have been embroiled in various disputes since the miner took control of the project in 2010. When Jacques was previously head of the copper unit, he was able to diffuse much of the tension after inviting former Prime Minister Chimediin Saikhanbileg to his west London home. The gesture helped pave the way for a crucial $4.4-billion financing accord last year to fund the underground expansion.

Rio’s board has been in the country this week visiting the mine located about 340 miles (547 km) south of Ulaanbaatarand 50 miles north of the border with China. Jacques said he had met with new Prime Minister Erdenebat Jargaltulgain the city earlier this week.

“We had a very open conversation on where we are in relation to our joint project,” he said. Construction of the underground expansion is “well underway” and about 1 600 people are working on the project, he added. Staffing is expected to reach 2 400 by year-end.

Frustrated voters swept the Democratic Party from power in June, giving the Mongolian People’s Party an overwhelming mandate to address the deterioration of the economy. This month, the country requested assistance from the International Monetary Fund to help it deal with an economic crisis stemming from a downturn in mining since 2011.

Following the change of power, the government recently ousted three board members at the State-owned miningcompany that helped steer Oyu Tolgoi out of the long-standing dispute between Rio and the government.

Last December, Rio said it paid a total of $1.3-billion in taxes, fees and other payments to the government of Mongolia. In 2015, taxes to the country were $278-million. Rio has been shipping concentrates by road to customers, mostly in China, since 2013. The mine is expected to be in operation for more than 75 years.

Return of power to BHP's Olympic Dam mine delayed due to high winds

Oct 7 Power is unlikely to be restored to the area near BHP Billiton's Olympic Dam copper mine in South Australia before Monday, nearly two weeks after a massive outage forced it to shut down, power supplier ElectraNet said on Friday.

BHP said the time taken to restore power was "regrettable," and that most operations remained on care and maintenance.

ElectraNet said crews were working to erect temporary towers and restring transmission lines but winds in the area were causing delays.

"Work is progressing steadily and while we are continuing with our best efforts to aim for Sunday, we expect a completion date of Monday may be more realistic, provided weather conditions remain stable," ElectraNet's manager of network services, Simon Emms, said.

BHP is losing an average of 567 tonnes of copper production at a cost of $2.7 million a day, based on last year's output of 203,000 tonnes and current metals prices of around $4,800 a tonne.

The restoration of power could also see the neighbouring Prominent Hill copper mine resume operations.

The blackout occurred after strong winds destroyed major power lines and lightning struck a power plant.

Court finds Eritreans' case against Nevsun can proceed in Canada

A Canadian court ruled on Thursday that a lawsuit against Nevsun Resources Ltd by Eritreans who say they were forced to work at the company's Bisha mine can proceed in British Columbia, but not as a single case, according to a copy of the judgment seen by Reuters.

The Vancouver-based miner argued that the case should be dismissed and that any lawsuit should be heard in Eritrea, not Canada, an argument the court rejected.

But the judge granted an application by Nevsun asking the court to find that the case could not continue as a representative action, similar to a class action, noting that the six workers named in the case made slightly different allegations. The Eritreans will need to file separate lawsuits, which could make the case more complex and expensive.

Joe Fiorante, one of the lawyers representing the workers, said he was not concerned about that part of the decision.

"We're reviewing that aspect of the decision but the case will certainly go forward," he said. "This is a big win for us."

Nevsun said it is studying the ruling and considering an appeal of the decision that the action can proceed at all.

If Nevsun loses at trial, the company could be forced to pay compensation for "severe physical and mental pain and suffering."

Nevsun says its mine is a model development. In legal filings, it said the Eritrean military never provided labor to the mine. Even if it did, the company argues, Nevsun was not directly responsible for employing the workers.

In affidavits filed with the court, six men, who have since left Eritrea, said they were forced to work at Bisha from 2008 to 2012 and that they endured harsh conditions at the Eritrean gold, copper and zinc mine, including hunger, illness and physical punishment at the hands of military commanders.

They said they were conscripts in the country's national service system when they worked at Bisha, working not for Nevsun directly but for government-owned construction firms subcontracted to build the mine.

Some workers backed up the company in affidavits, saying they worked at the mine voluntarily and never experienced mistreatment.

The United Nations has said Eritrea's national service program is "similar to slavery in its effects" - an allegation the government rejects. Eritrea, ruled by a former Marxist guerrilla leader since its independence from Ethiopia, sees conscription as crucial to its security.

US zinc recycler Horsehead Holding Corp has emerged from nearly eight months in bankruptcy and now is expected to turn its attention to mapping plans to repair and restart its idled Mooresboro plant in North Carolina, according to court filings.

The Pittsburgh-based company exited Chapter 11 reorganization on September 30, the effective date of a final reorganization plan approved on September 9 by Judge Christopher Sontchi of the US Bankruptcy Court for the District of Delaware, the company's attorneys said in a filing.

Under the plan, substantially all of Horsehead's long-term debt was wiped out with about $205 million in senior secured debt converted to equity in the newly named company -- Horsehead Holding LLC.

The company will attempt to chart a new course for its most valuable asset, Mooresboro, idled in late January prior to Horsehead and certain of its subsidiaries filing for bankruptcy on February 2, less than a month after they defaulted on loan agreements with two banks.

Zinc, lead prices break free from long term downtrend

Base metals have also enjoyed a stand-out 2016 with across the board gains year-to-date. Measured from recent lows which mostly occurred at the end of 2015 and in January and February this year the recovery in prices this year is even more impressive.

While bellwether copper has also been lacklustre adding only 1.5% in 2016, zinc is the top performer for the year with a 49% gain since January and the recent rally in lead means the metal now boasts a 16.5% rise in 2016 scaling $2,000 a tonne in September.

Aluminum and cobalt have both enjoyed double digit gains so far this year while tin (+39% just over $20,000) and nickel (+17% holding above $10,000) have recovered after wobbles over the summer. With the exception of copper base metals are currently trading at their 2016 highs after a strong third quarter.

BMI Research in a research report says the positive momentum is likely to continue as additional infrastructure stimulus measures by China and developed markets will provide a boost to prices for the next six to nine months.

The graphs for zinc and lead look particularly encouraging, with both metals breaking out of a long term downtrend:

Attached Files

Chile’s Codelco, the world's top copper miner, has once again made drastic changes to its ambitious five-year investment plan as falling copper prices continue to dry up the company’s earnings.

The state-owned miner, which faces what its chief executive Nelson Pizarro recently called its “worst crisis ever” since created in 1976, has decided to reduce its investment budget by $2.25 billion, local news site El Pulso reports (in Spanish).

Phase two of the Radomiro Tomic sulphur project will be postponed to 2024, while construction of a new level at El Teniente, originally set to be done by 2020, now it is expected to complete in 2023.

The figure, though significant, is minor when taken in the context of Codelco’s ambitious investment plan,originally pegged at $25 billion (now sitting at $18bn), aimed at upgrading its aging mines and dealing with dwindling ore grades.

"We have modified our strategy for the projects. Instead of carrying them out simultaneously, development will now take place sequentially," the miner said in an internal newsletter sent to staff quoted by El Pulso.

Among the affected plans, Codelco noted that phase two of its Radomiro Tomic sulphur project will be postponed to 2024, while construction of a new level at El Teniente, originally set to be done by 2020, now it is expected to complete in 2023.

The company, however, won’t touch a much neededexpansion project at its century-old Chuquicamata mine underground, currently underway, which is due to be completed by 2019.

The investment cuts come despite Chile’s government injected $600 million of capital into the copper giant earlier this year.

But Codelco, which hands over all its profits to the state, has received only 10% of its surplus over the past decade. In comparison, private copper miners reinvest an average of about 40% of their profits.

The miner’s output amounts to around a tenth of global supply and it has been one of the main forces behind Chile’s transition from one of Latin America’s poorest countries to one of the richest over the past 40 years.

Base metals suffered a broad-based sell-off Tuesday after the dollar hit a multi-month high, but the slide has since slowed down.

U.S. judge dismisses aluminium price-fixing litigation

A federal judge on Wednesday dismissed nationwide litigation by aluminium purchasers who accused banks and commodity companies of conspiring to drive up prices for the metal by reducing supply, forcing them to overpay.

The decision by U.S. District Judge Katherine Forrest in Manhattan halts, for now, three years of litigation against Goldman Sachs Group Inc, JPMorgan Chase & Co, mining company Glencore Plc, and various commodity trading, mining and metals warehousing companies.

Purchasers had accused the defendants of colluding from 2009 to 2012 to manipulate prices by hoarding inventory.

They claimed that this caused delays of up to 16 months to fill orders, leading to higher storage costs, which in turn inflated aluminium prices and the cost of producing cabinets, flashlights, soft drink cans, strollers and other goods.

In August, the 2nd U.S. Circuit Court of Appeals in Manhattan upheld Forrest's dismissal two years earlier of antitrust claims by "indirect" commercial end users and consumer end users.

Applying that ruling, Forrest on Wednesday said related claims by "first level" purchasers, which she allowed to go forward in March 2015, must also be dismissed.

She said both cases rested on the same "core assertion" that Platts Midwest Premium, a component of aluminium prices, rose because of alleged "shenanigans" in aluminium warehouse services.

"There is no allegation or evidence in the record that defendants engaged in any anticompetitive conduct outside of the aluminium warehouse services market," Forrest wrote. "Profit by defendants or losses by plaintiffs subsequently experienced in physical aluminium is irrelevant to antitrust standing."

Lawyers for the purchasers did not immediately respond to requests for comment. Goldman spokesman Michael DuVally and JPMorgan spokesman Brian Marchiony said their banks were pleased with the decision. Glencore did not immediately respond to requests for comment.

Forrest concluded with a long footnote lamenting how a 2015 U.S. Supreme Court decision, Gelboim v. Bank of America Corp, could impede settlements of complex litigation by letting some plaintiffs--here, the indirect purchasers--appeal dismissals of their claims while other plaintiffs press on.

"In this case, the opposite has occurred," she wrote. "A 'Gelboim Appeal' has caused a case nearing final procedural stages to come to a halt. Perhaps this is the most just result. But plaintiffs will undoubtedly appeal--and if successful, the parties will be picking up where they left off two years hence."

The case is In re: Aluminium Warehousing Antitrust Litigation, U.S. District Court, Southern District of New York, No. 13-md-02481.

Peru's La Oroya smelter to be auctioned in first quarter of 2017

Peru's nearly 100-year-old polymetallic smelter La Oroya and the nearby copper mine Cobriza will likely be offered up in an auction in the first quarter of 2017, the head of the company tasked with finding a buyer said Wednesday.

Pablo Peschiera, director of consulting firm Dirige, said the two assets of the now-bankrupt company Doe Run Peru would likely fetch at least $100 million, though investments to upgrade the smelter could cost $700 million.

Peschiera said he was optimistic about the new bidding round that follows an August 2015 auction that failed to draw any offers as investors fretted over environmental standards, past pollution and demands from workers.

Dirige has asked the government to ease sulfur dioxide emission limits in La Oroya and to tweak rules to clarify that a new operator would not be liable for Doe Run Peru's obligations.

"The market is in charge. We'll launch the auction with whatever conditions are in place and hope that by then these changes will have been made," Peschiera said in an interview.

The smelter in Peru's central Andes was shuttered in 2009 when Doe Run Peru, owned by New York billionaire Ira Rennert's Renco Group, ran out of money to buy concentrates and pay for environmental upgrades.

The company left $650 million in debts unpaid, including $90 million to $100 million owed to workers, Peschiera said.

The smelter now only processes some zinc, employing a fraction of some 2,200 mostly furloughed workers.

A workers' strike scheduled next week to demand the rest of the smelter restarts could hurt sale prospects, Peschiera said, adding he hopes to persuade the union to call off the stoppage.

President Pedro Pablo Kuczynski's promise to revive La Oroya as part of his plan to boost the value of the country's mineral exports has sparked fresh interest from investors, Peschiera said.

Kuczynski, who took office in July, convinced Congress to give La Oroya more time to find a buyer and has slammed Peru's emissions standards as too strict, saying upgrading La Oroya's copper circuit would cost $500 million under current rules but only $200 million if Canadian standards applied.

Peru relaxed the sulfur emissions limit for La Oroya in 2014, but Peschiera said standards should be loosened further.

Kuczynski's environment minister told Reuters last month that air and water quality standards are under review.

Indonesia expects mining rule overhaul within weeks

Indonesia is finalizing an overhaul of its mining rules that could give companies up to five more years to build smelters, and reopen exports of nickel ore banned since 2014, the country's mining minister said on Tuesday.

The proposed changes provide a way around a 2017 deadline for full domestic processing of mineral ores, potentially pushing completion of that aim to 2022, but also possibly undermining investor confidence.

"We will provide an opportunity to companies building smelters, in the form of a relaxation ... in accordance with their smelter development progress," Mining Minister Luhut Pandjaitan said.

Miners that fail to build smelters within five years could have their mining permits revoked, Pandjaitan said.

Present rules would stop miners of copper, zinc, lead, manganese and iron from exporting concentrates after January 2017, after which only shipments of processed metals will be allowed.

The proposed change could be a breakthrough for miners such as U.S. giant Freeport-McMoRan Inc, for whom it would avert a stoppage of copper concentrate shipments from the giant Grasberg mine in Papua in far eastern Indonesia.

A Jakarta-based spokesman for Freeport did not immediately respond to requests for comment on the matter, but Indonesia's largest copper miner has previously said it was confident the government will not push ahead with the 2017 deadline, as the move could harm the economy.

NICKEL ORE POLICY

The government is also looking to possibly change rules on nickel ore with a 1.8 percent metal content, "because no one can process it domestically. Perhaps we will consider exporting it," Pandjaitan said.

Nickel companies have said they fear the rule changes could weaken metal prices, undermine confidence in the newly budding smelting industry and risk up to $12 billion in investments.

The Philippines took the crown as the world's top nickel ore exporter after Indonesia banned nickel ore shipments, and now accounts for around one-quarter of the world's mined nickel supply, most of which is shipped to China.

But Indonesia has found compensation in shipping pig iron to China, India and other buyers, and this industry now worries that resuming ore exports could undermine the prices for such semi-finished and refined metals.

"Actually no one supports there being ore (exports) any more," Jonatan Handojo, executive director of Indonesia's main smelter industry association, told Reuters.

Overturning the ban would go against the wishes of most participants in Indonesia's nickel industry, Handojo said.

He dismissed a "handful" of companies, such as Indonesian state miner Aneka Tambang, which hope that Indonesia will again open up nickel ore exports to prop up income and support financing for smelter investments.

EXPORT TAX?

As part of the overhaul, the finance ministry is working on a progressive export mineral export tax, to be imposed in stages according to how far companies have advanced with their smelter development, Pandjaitan said.

Further details of this and the mining overhaul are expected within weeks, Pandjaitan said.

"There is no way we can satisfy everyone, but we are trying to be as fair as possible, and to act in the interests of the government, the people of Indonesia and investors in that sector," he said.

Indonesia's growth cooled to its slowest in six years in 2015, partly as a result of weaker returns from commodities, and the government has been rolling out new measures this year to reenergize the economy and boost its revenues.

Nickel prices hit a seven-week high of $10,900 a tonne on the London Metal Exchange last week, after the Philippines intensified its environmental crackdown on nickel miners.

Olympic Dam still on care and maintenance

Operations at the Olympic Dam copper, gold and uranium mine, in South Australia, remained on care and maintenance, mining giant BHP Billiton said.

Operations were suspended and the site de-mobilised following a severe storm in South Australia, which resulted in state-wide power outages.

BHP said at the time that back-up generators were providing power to critical infrastructure, which would allow a restart of operations when power was restored.

The miner said in a statement that the Olympic Dam mine was now receiving some power from the grid, after power was restored to the Roxby Downs township, and added that with the additional generation capacity sourced and connected, it would ensure asset stability and integrity of the operations, until full power was restored and the operations could resume as normal.

BHP was expected to release the production impacts of the power outage during its September quarterly report.

Platts assesses Q4 Japan aluminium premiums at $75/mt plus LME, CIF

Platts assesses Q4 Japan aluminium premiums at $75/mt plus LME, CIF

Platts on Friday assessed the premium for imported primary aluminium in the fourth quarter of 2016 at $75/mt plus London Metal Exchange cash, CIF main Japanese ports, down 18% from $90-93/mt plus LME cash CIF Japan for Q3.

The Q4 assessment was on the basis of 10 settlements in total at $75/mt plus LME cash CIF Japan, for seaborne P1020/P1020A ingot for loading over October-December, for a volume higher than 500 mt/month.

The total volume for the 10 settlements was 9,000 mt/month or more. All of the settlements were also under annual contracts where the total volume is set for the year while premiums were negotiated quarterly.

Platts specifications are for all quarterly settlements on a CIF main Japanese port basis, negotiated prior to Q4 between two unaffiliated counterparties, for P1020/P1020A 99.7% primary aluminium ingot, with payment in cash against documents, for volumes of 500 mt/month or more.

Four Q4 settlements were not taken into account for the assessment.

One deal reported closing at $60/mt plus LME cash CIF Japan was determined to have fallen outside the Platts' specifications, due to a lack of repeatability. The deal was for 1,500 mt/month of Australian, South African, Middle Eastern or other origins universally understood to be Good Western.

Two deals reported closing at $75/mt plus LME cash CIF Japan were not accounted for, as the parties were affiliated.

One deal, also at $75/mt plus LME cash CIF Japan, was for less than 500 mt/month.

Not all 20 mines facing suspension may be halted – Philippine Minister

The Philippine government may not freeze all 20 mines facing suspension for environmentalinfractions and they will be given time to address any lapses, the Minister in charge of mining said on Friday.

"Yes if they are able to fix whatever" needs to be fixed,Environment and Natural Resources Secretary Regina Lopez told Reuters when asked if it is possible that not all 20 mines will be suspended.

"Some of the violations though will take time to fix. So they need to use their employees to fix it."

Lopez's agency said on Tuesday that 20 more mines have been recommended for suspension and gave them seven days to explain any violations and submit measures to rectify them.

Manila has already halted 10 mines and suspending another 20 would leave only 11 operating mines in the Southeast Asian country, which accounts for nearly a quarter of the world's mined nickel supply – most of which is shipped to China.

Steel, Iron Ore and Coal

Australia’s resources and energy commodity exportearnings are forecast to increase to A$176-billion in 2016/17, up 12% from an estimated A$157-billion in 2015/16.

In its latest Resources and Energy Quarterly, the Department of Industry, Innovation and Science shows that spikes in metallurgical coal and iron-ore prices are likely to boost earnings in the year ahead.

The spikes reflect unexpected supply disruptions in Indonesian coal mines and the strength of the Chinese construction sector, chief economist Mark Cully said on Friday.

“Prices for most construction and steel-making raw materials continued to grow in the last three months, despite expectations of decline, because of unexpectedly resilient demand from China’s construction sector and unforeseen supply disruptions.”

Cully noted that the speculative activity in China’s commodity futures markets that led to high spot price volatility in the first half of 2016, had tapered off. This was supported by measures to reduce speculative trading, including increased commission fees, margin requirements and trading restrictions.

China’s economy and its demand for construction raw materials was slowing, as it transitions away from investment-led growth to consumption-led growth, Cully added. While any slowdown in the short-term remained sensitive to government policy and stimulus measures, Cully said that the likelihood of significant increases in demand from China for resource commodities was limited.

“Australia’s suppliers are well-placed to satisfy demand forresources and energy over the next fifteen months, despite difficult operating conditions. In particular, production of most bulk commodities is forecast to increase, even as prices decline.”

Export values have also been supported by the Chinese government’s efforts to stimulate its economy. Given the temporary nature of many of these factors, it is likely that price increases will be temporary, with falls in coal and iron-ore prices expected in 2017.

The strongest growth in export earnings is expected to come from LNG, which is forecast to increase 41%, from A$17-billion in 2015/16 to A$23-billion in 2016/17, supported by additional production at the Gorgon project and new capacity coming on line on the east coast.

Continued growth in the volume of most bulk commodities exports is also expected to contribute to higher exportearnings over the outlook period. The value of Australia’s exports of iron-ore is forecast to increase 13%, to A$54-billion in 2016/17.

However, although the price recovery in the first half of 2016 delivered some support to producers, the generally subdued outlook for prices means producers are likely to remain underfinancial pressure in the near term.

In its quarterly report, the Department of Industry,Innovation and Science noted that global bulk commodities markets were likely to remain well supplied over the outlook period as major investments undertaken over the last decade reached full production capacity.

However, there may be some tightness in global coal supply in the near term owing to production constraints in Indonesiaand further declines in the volume of exports from the US

Production volumes for metals commodities are also generally expected to grow over the next 15 months.

Gold production is forecast to increase, supported by further growth in recycled supply, while copper supply is also expected to grow as additional supply from new investments in Peru and Kazakhstan offsets declines elsewhere.

In contrast, world nickel production is forecast to fall over the remainder of 2016 as a result of shutdowns in thePhilippines. Nickel production is forecast to increase again in 2017 in line with returning capacity in the Philippines andIndonesia.

Markets for energy commodities are expected to remain well-supplied over the outlook period owing to additional LNGproduction associated with new projects, and elevated stocks of crude oil and petroleum products.

The Australian Petroleum Production and ExplorationAssociation (Appea) said on Friday that the latest report provided equal measures of optimism and disappointment.

The Australian Competition and Consumer Commission has expressed concerns about Australian freight companies Aurizon or Pacific National acquiring Glencore Coal's Hunter Valley GRail coal haulage business and set a deadline for a decision on the matter for December 15, the ACCC said Thursday.

The competition watchdog is assessing proposals in the bidding process against the alternative scenario of a new player entering the market by acquiring GRail, it said.

"The Hunter Valley coal haulage market appears to have high barriers to entry, so we would expect the addition of a third competitor to have a significant effect upon the market," ACCC chairman Rod Sims said.

"In contrast, an acquisition by Aurizon or Pacific National would essentially be a continuation of the status quo where there are two active players in the Hunter Valley coal haulage market," he said.

Pacific National hauls the majority of the coal on the Hunter Valley Rail Network in the Australian state of New South Wales, with Aurizon hauling the second largest volumes and there has been little or no new entry before or since, Sims said.

"There are some examples of coal producers acquiring their own rolling stock, but Glencore Coal is the only Hunter Valley coal producer to have done so for a majority of its coal haulage requirements," he said.

"Coupled with the fact that Glencore Coal is the largest coal producer in the Hunter Valley, this is a platform for entry that is unlikely to be replicated in the foreseeable future," he said.

But, the ACCC said it also recognises that coal producers, generally well-resourced and sophisticated parties, may be able to protect their own interests, even if Aurizon or Pacific National acquires GRail.

"We are going to be exploring their ability to leverage competition between Aurizon and Pacific National or to bypass both haulage providers by acquiring their own rolling stock or by sponsoring new entry," Sims said.

US-based Genesee & Wyoming is also bidding for the network, Australian media reports say.

G&W has teamed up with Macquarie Infrastructure and Real Assets, according to the Australian Financial Review.

G&W is also the current operator of GRail's rolling stock.

The business unit has grown from three coal trains in 2010, to a modern fleet of nine locomotive units and is now the third largest coal haulage operation in Australia, Glencore says.

GRail has an estimated market value of A$1.1 billion-A$1.5 billion ($840 million-$1.1 billion) based on the unit's annual earnings before interest, tax, depreciation and amortization of A$100 million, according to industry sources.

North Queensland coal exports rise 9% to 15-month high in September: NQBP

Coal exports from the Hay Point, Dalrymple Bay and Abbot Point terminals in the Australian state of Queensland rose by 9% in September, from August, to a 15-month high of 12.99 million mt, led by strong gains at the Dalrymple Bay and Abbot Point terminals, the North Queensland Bulk Ports Corporation said Wednesday.

September's combined throughput from the three terminals breached the year-to-date monthly average of 12.02 million mt by 970,000 mt, the data showed.

From January to September, exports totaled 108.21 million mt, which is higher than the same period last year, when it was at 105.98 million mt.

Despite the multi-month high in September, there remains capacity for significantly higher exports. The three facilities have a combined nameplate export capacity of 190 million mt/year, and in September they operated at an annualized rate of 158.05 million mt/year.

For the year to September, the terminals saw an annualized rate of 144.67 million mt/year.

The rise in September was mainly driven by increased exports from the Dalrymple Bay facility. Exports from the 85 million mt/year nameplate capacity terminal surged 19% month on month in September to 6.67 million mt, which, like the combined total, was a 15-month high from the facility.

The Dalrymple Bay Coal Terminal's September annualized rate was just 3.85 million mt/year shy of its annual nameplate capacity, hitting 81.15 million mt/year. DBCT is a Queensland state government-owned common user facility.

The Adani Group-owned Abbot Point Coal Terminal also saw a strong month- on-month rise, up by 28% in September to 2.31 million mt, which breached the year-to-date monthly average for the facility of 2.20 million mt, according to NQBP data.

APCT's annualized rate for September of 28.11 million mt/year, however, remains well below its nameplate capacity of 50 million mt/year.

Coal transport on the Newlands Coal Rail System, which links several metallurgical coal mines to the Abbot Point Coal Terminal, was disrupted due to a derailment September 11, operator Aurizon said during the month. Transport was to resume September 19, Aurizon had said at the time.

BMA's Hay Point terminal bucked the trend and posted losses in September. Exports totaled 4.01 million mt at the terminal during the month, down 12% from August, and below the year-to-date monthly average of 4.14 million mt/year, according to the data.

The terminal operated at an annualized rate of 48.79 million mt/year during September, which compares against its nameplate capacity of 55 million mt/year.

Arch cut debt after completing financial restructuring and emerged from court protection, with new equity to trade on the New York Stock Exchange under ticker symbol ARCH, it said in a company statement.

"We are particularly pleased to be emerging in a resurgent metallurgical market, and look forward to similar strengthening in thermal coal markets in the months ahead," Arch CEO John Eaves commented in the statement.

FBR factored in Arch's average 2017 met coal prices at $82.02/st Mine, with costs at just over $53/st Mine. Company guidance was for met coal costs to fall around $50/st.

"While we always considered Arch a strong operator, we believe the company is now positioned to prosper in almost any coal price environment," FBR analysts led by Lucas Pipes said in a note.

"Near term, we see the company's met coal exposure as its greatest catalyst," FBR said as it initiated coverage of Arch's new shares at outperform.

"Arch's met coal products include a range of product types, but importantly they include a large contribution of prized high-vol A qualities. We believe both in the domestic market as well as internationally into Europe, high-vol A grade coal is considered scarce while being an essential part of many steelmakers' met coal blends."

ARCH UPDATE

The St. Louis-based group expects met coal sales at between 7 million-7.5 million st in 2017, and said the vast majority of the volume is yet to be committed and therefore is exposed to current and potentially higher prices, in a presentation to investors released earlier this week.

Arch said it intends to build on European market share, while expecting growth in Japan, South Korea and India, and said a focus on high-vol, fluidity coals may aid its position.

Premiums for high-vol A rose on shortages, with Platts data showing a diversion with longer term price trends for US low-vol, meanwhile benchmark grade spot coal prices surpassed $200/mt FOB to triple on year-to-date lows.

"While the US share of European met supply will fluctuate somewhat, high-quality, high-vol coals will remain a cornerstone of European coke blends," Arch said in the investor presentation.

"Arch is focused primarily on the high-vol segment, and enjoys a quality and freight advantage relative to Australian supply. If vessel rates increase and/or Asian demand for Australian met coal strengthens, the US could compete for still greater share in Europe."

Blackhawk Mining, Alpha Natural Resources, Contura and smaller US miners are similarly exposed to US high-vol HCC, and may capitalize on price and market trends. Traders Xcoal Energy & Resources, Integrity Coal Sales have supplied more US met coal than Arch.

Cia Siderúrgica Nacional SA is seeking a valuation of between $30 billion and $35 billion for iron ore unit Congonhas Minérios SA, in which the Brazilian steelmaker is in talks to sell a minority stake, a person familiar with the matter said on Wednesday.

According to the person, who asked for anonymity since the process is confidential, China Brazil Xinnenghuan International Investment Co is interested in buying 20 percent to 25 percent of Congonhas Minérios directly from CSN.

Talks are progressing slowly and may not result in a deal, the person said.

Reuters reported on Sept. 26 that both companies were discussing the transaction, whose outcome also hinges on the ability of CSN to secure long-term supply contracts from CBSteel, as the Chinese company is known.

A spokesman for CSN did not have an immediate comment. Efforts to reach media representatives for CBSteel were unsuccessful.

The stake sale in Congonhas Minérios is Chief Executive Officer Benjamin Steinbruch's most ambitious asset divestiture plan yet for CSN, which has the largest debt burden among Brazilian steelmakers. Optimism over the sale has driven shares of São Paulo-based CSN up 7 percent over the past week.

Congonhas Minérios was created at the end of 2014, through the merger of CSN's fully owned Casa de Pedra mine and Namisa, an ore production joint venture with six Asian companies. Casa de Pedra has one of Brazil's best-quality iron ore reserves.

The six Asian companies that own a combined 12 percent of Congonhas Minérios would keep their stakes unaltered if a deal between CSN and CBSteel materializes, the person said.

Coking coal surge could kill quarterly pricing

The stunning rise in the price of coking coal shows now signs of reversing, and the nearly three-fold rise in the price of the steelmaking raw material since hitting multi-year has pushed the quarterly benchmarking system to breaking point.

Metallurgical coal was exchanging hands at $213.40 on Tuesday according to data provided by Steel Index as it consolidates at higher levels following weeks of panic buying not seen since 2011, when floods in key export region in Queensland saw the price touching to $335 a tonne.

A new research note Adrian Lunt, head of commodities research at the Singapore Exchange, says the traditional quarterly benchmark mechanism has "arguably been losing relevance for some time, but the recent spot market volatility has put it under potentially fatal strains":

The commoditisation and rising adoption of indexation has been a key feature in the seaborne coking coal market in recent years. In recent years the quarterly settlement has largely followed the spot market, and a prolonged period of price stability perhaps enabled the quarterly benchmark to persist (albeit pricing an ever-shrinking portion of the international market).

During Q3, the daily spot price averaged almost $133 per tonne, approximately 44% higher than the Q3 quarterly benchmark agreed in late June. With spot and benchmark pricing deviating more than ever, strains are likely to persist on the outdated quarterly pricing mechanism. Continued market volatility could spur a more widespread transition to index-linked pricing over the coming months, which may in turn serve as an important catalyst in the development of the international coking coal derivative market.

Attached Files

India expects SAIL/ArcelorMittal JV to start production in two years

India expects a joint venture between state-owned Steel Authority of India Limited (SAIL) and ArcelorMittal to start producing automotive-grade steel in two years, a government official said on Tuesday.

Officials from the two companies are due to meet on Thursday to take forward talks about a proposed 60 billion rupee ($902 million) plant that will produce 1.2 million tonnes of steel per year to begin with, Steel Secretary Aruna Sharma told Reuters.

SAIL and ArcelorMittal, the world's largest steel producer, signed a preliminary agreement in May last year to expand in what is one of the world's fastest growing steel markets and a major car exporter.

"In another two years it should be in the manufacturing stage, provided we freeze everything within one and a half months and in December we take off," Sharma said. "We will go more for import replacements. We have solutions for it."

She said the government was working on raising demand for steel in India - whose per-capita consumption of about 60 kg is less than one-third of the global average - by replacing concrete with steel in major infrastructure projects.

The World Steel Association expects India's steel demand to rise 5.4 percent this year and next, even as countries such as China see a decline. (bit.ly/2dsfLgw)

Apart from ArcelorMittal, India's growing steel demand is also keeping other major companies such as South Korea's POSCO interested, despite regulatory hurdles and difficulties acquiring land.

Sharma, who moved to the steel ministry more than two months ago, has already met POSCO officials who are eager to expand in India despite the de facto scrapping of the company's proposed $12 billion steel plant in the eastern state of Odisha after a decade of protests over land.

"They will like a plug-in kind of an arrangement (to set up a new plant)," she said.

Sharma also said that to protect the domestic steel industry from cheap imports, the government may impose provisional anti-dumping on 21 products within two weeks.

Top Indian steel makers such as JSW Steel Ltd, Tata Steel Ltd and Jindal Steel & Power Ltd have lobbied the government hard to take more measures to protect their margins from cheap imports from China, Japan and South Korea.

Indonesian coal miner Bumi posts record loss of $1.9 bln

Indonesian coal miner PT Bumi Resources Tbk reported a record loss of nearly $2 billion for 2015 on Tuesday, mainly due to asset impairments and write-offs for its receivables.

Bumi's net loss of $1.9 billion for the year ended Dec. 31, 2015 was far wider than a revised loss of $370.5 million for 2014. That was the biggest annual loss it ever posted, according to Thomson Reuters data.

Bumi, part of the Bakrie Group conglomerate, has been struggling to service its debt as an oversupply of coal and weaker demand from China hurt its cash flow. The coal miner had previously delayed the release of its 2015 financial results.

Bumi made a loss of $885.5 million due to asset impairments and $522.6 million as a result of writing off receivables, it said in a filing to the Jakarta stock exchange. Revenue fell to $40.5 million from $61.9 million.

Bumi impaired Gallo Oil, which operates two oil and gas exploration concessions in Yemen, "owing to stressed market and economic conditions in the sector," Bumi director Dileep Srivastava said in a text message.

Other assets impaired include coal mines on the Indonesian island of Sumatra, Srivastava said. The company also wrote off some receivables from Indonesian company Bukit Mutiara due to its "potential insolvency", he said.

US coal legend Ernie Thrasher close to bagging Anglo mines

Apollo Global Management is said to be in exclusive talks to buy Anglo American's metallurgical coal mines in Australia.

According to the Financial Review, the Grosvenor and Moranbah mines could fetch around $1 billion and the private equity firm could sign a deal within two weeks:

Apollo is working in a heavyweight consortium with Pennsylvania coal exporter Xcoal Energy & Resources, the largest exporter of coal in the United States and founded by coal legend Ernie Thrasher.

Downsizing may no longer be the right strategy for Anglo with metallurgical coal prices doubling during the third quarter

The Queensland-based operations have been up for sale since February, when chief executive officer Mark Cutifani outlined a radical divestment strategy to generate between $3bn and $4bn from asset sales this year to drive down debt.

Other firms have also circled the coal mines at various stages of the process, including BHP Billion through its joint venture with Japan's Mitsubishi, South32, Glencore and US-based Coronado Coal, with varying reports as to which remain in contention.

Earlier this year, Anglo sold its 70% stake in Foxleigh coal mine, also located in Queensland, to a consortium led by Taurus, an Australian fund manager that invests in the commodities industry. The sale amount was not disclosed.

Some observers have commented that downsizing may no longer be the right strategy for Anglo with metallurgical coal prices doubling during the third quarter, iron ore 50% above its December lows and a broad improvement in base metal prices.

Metallurgical coal was exchanging hands at $213.40 on Monday according to data provided by Steel Index as it consolidates at higher levels following weeks of panic buying not seen since 2011, when floods in key export region in Queensland saw the price touching to $335 a tonne.

Iron miners face test of discipline as China challenge looms

The world’s largest iron ore producers will need to exert tight control over supplies to keep prices at about $45 a metric ton as China’s drive to weed out unwanted steel capacity poses risks to demand, according to Singapore-based DBS Group Holdings.

The commodity’s rally in 2016 may come under pressure as consumption in China is poised to weaken in the coming years, chief investment officer Lim Say Boon said in a quarterly report. Iron ore was last at $55.86 a dry ton, and hasn’t traded below $45 since February, according to Metal Bulletin.

Iron ore sagged in September, eroding this year’s surprise advance, on resurgent concern that supply growth will again swamp the market even as some miners say they are now prioritizing the value of exports over volumes. With Brazil’s Vale set to start a four-year ramp-up of its S11D project, banks from Citigroup to Morgan Stanley, as well as miner BHP Billiton, have said the additional output will probably contribute to weaker prices.

“Although the price of iron ore has been in an uptrend since the start of the year, it could be difficult for the market to sustain those gains,” Lim wrote in the report, which was received on Monday. It didn’t list specific price forecasts. “Australian and Brazilian producers will have to maintain tight shipment discipline to keep the price” at about $45, he said.

Rising Production

Ore with 62% content delivered to Qingdao lost 5.3% in September, capping the first back-to-back monthly loss since November 2015, according to Metal Bulletin. It remains 28% higher in 2016 after a three-year tumble marked by rising production and persistent global oversupply.

Australia’s two biggest producers have slowed the pace of supply growth as a decade-long expansion nears an end. BHP Billiton, the world’s largest miner, has forecast that its mines in Australia may expand annual output by as little as 3% in the 12 months to June 30, it said in July.

Rio Tinto Group’s Jean-Sebastien Jacques, who was appointed chief executive officer in July, said the following month that its iron ore strategy “is not about volume, it’s about value.” The world’s second-biggest exporter is adding to full-year shipments at the slowest rate since 2012, while its annual output from Australia may be unchanged in 2017 as it addresses difficulties completing an autonomous train program.

Still, plenty of banks have flagged prospects of rising low-cost supply from the largest-producing nations. Shipments from Australia will expand to 934 million tons in 2020 from 835 million this year, while Brazilian cargoes rise to 480 million tons from 371 million, Citigroup said last month. The bank reiterated its outlook for ore dropping to $45 next year and $38 in 2018.

Arch Coal is projected to have $311 million in cash on the balance sheet and a "sustainable capital structure" when it emerges from Chapter 11 bankruptcy protection, the company said.

The outlook looks rosier for Arch, the St. Louis-based producer that filed for bankruptcy protection in January and could emerge as early as this week.

Upside for Arch includes a steep increase in metallurgical coal prices and higher forecast natural gas prices, which would increase demand for thermal coal.

"We expect to emerge with over $300 million of cash on the balance sheet," the company said in an investor presentation Friday. "Arch expects to be cash flow positive after emergence."

The company will have eliminated nearly $5 billion in debt to $363 million and reduced interest expenses by $329 million to $33 million through bankruptcy, it said.

It will have removed its self-bonding obligations in Wyoming and other states, replacing them with $550 million in surety bond liabilities with "favorable collateral terms and rates."

Arch's assets include both high and low A and B mines in Appalachia, along with bituminous and subbituminous thermal coal mines in the Illinois, Uinta and Powder River basins.

Its largest mine, Black Thunder in the Southern PRB, produced nearly 100 million st in 2015.

Higher metallurgical coal prices have given US met coal producers an advantage, particularly US high-vol coal into Europe. Arch said. The company expects to produce 7 million-7.5 million st of met coal in 2017, most of which is "uncommitted and exposed to rising prices," it said.

Opportunities for thermal coal have returned as natural gas prices have rebounded to levels approaching $3/MMBtu, moving more Powder River Basin mines into the money.

Additionally, Arch and other producers could regain lost market share as coal-fired power plants are operating at below a 50% capacity factor and could run at "much higher levels if market forces allow," the company said.

Attached Files

China's iron ore party rolls on in September, underpinning prices

China's appetite for imported iron ore continued unabated in September, with vessel-tracking data showing seaborne arrivals should at least match the strength shown in recent months.

Shipping data compiled by Thomson Reuters Supply Chain and Commodity Forecasts shows that 85.24 million tonnes of the steel-making ingredient arrived at Chinese ports in September.

This was higher than the 82 million tonnes estimated for August and only slightly below the 85.67 million for July, which was the highest so far this year.

Vessel-tracking data doesn't exactly tally with official Chinese customs numbers, with the 647.8 million tonnes recorded for the first eight months of 2016 being 3.26 percent below the customs figure of 669.65 million tonnes.

Preliminary customs data for September is expected to be released next week.

Much of the difference can be explained by vessel-tracking not capturing iron ore imports that arrive by land, such as the 3.6 million tonnes from Mongolia in the first eight months, or from countries where ascertaining what ships are transporting is challenging, such as North Korea.

Nonetheless, the September ship data suggests that iron ore imports by China, which buys about two-thirds of global cargoes, remained robust, thereby underpinning the sustainability of this year's rally in prices.

Spot Asian iron ore <_.IO62-CNISI> ended at $55.20 a tonne on Sept. 30, staying near the middle of the roughly $11 range it has traded in since June.

Prices are up 28.7 percent so far this year, although iron ore is down from its peak in 2016 of $68.70 reached in April amid what many analysts believed was a hot-money speculative bubble in the Chinese domestic market.

The fact that iron ore managed to hold the bulk of its gains so far this year, even after the authorities in Beijing took steps to limit speculation on the country's domestic commodity exchanges, suggests that it has found a more secure footing.

Much of this is built on the fact that China is producing more steel than forecast, with crude steel output gaining 3 percent in August from a year earlier, the sixth straight monthly increase.

For the first eight months of the year, steel output was 536.3 million tonnes, down a mere 0.1 percent over the same period in 2015, and casting doubts on Beijing's commitment to reduce excess capacity.

It's unlikely that steel output will decline over the whole of 2016, given that prices remain solid, with benchmark Shanghai rebar up 34 percent in yuan terms so far this year.

Steel demand is being led by a revived housing sector in China, with ANZ Banking Group saying in a research note on Sept. 29 that it expected this cycle to last 12-18 months, suggesting relatively strong steel demand lasting through 2017.

If this is the case, it's further likely that demand for imported iron ore will remain robust as well, which suggests that the price gains seen so far in 2016 are sustainable.

IRON ORE SUPPLY KEY TO OUTLOOK

Much will depend on how much new supply is added to the seaborne market, and whether this will be sufficient to exert downward pressure on prices.

Brazil's Vale, the world's biggest iron ore shipper, expects to add 28 million tonnes in 2017, representing about 58 percent of the global addition to seaborne supplies, the company said on Sept. 28.

New supply from Australia, the top exporting nation, may be muted, with the major additions coming from the ongoing ramp up of the 56-million tonne a year Roy Hill mine in Western Australia state.

Views within the industry are mixed, with Vale and number three Australian miner Fortescue Metals Group expecting the current stability in the market to continue, while second-ranked Australian producer BHP Billiton said in August that prices were still more biased to the downside.

In some ways iron ore prices are currently trying to be like the baby bear's porridge, not too hot and not too cold.

If they rise too much, it's likely Chinese domestic output that has been rendered uncompetitive will return to the market, but they also have to be wary of cooling by adding too much supply.

India to change rules governing captive coal mines

India’s Coal Ministry is finalising a new coa lpolicy aimed at liberalising rules governing captive and merchant coal mines against a backdrop of surplus availability of the dry fuel in the domestic market.

The new policy is expected to be unveiled within the next month, after the Indian festival holiday season starting next week.

Among the changes proposed, the most major pertained to captive coal mines, with the new policy said to permit captive coal mining leaseholders making excess production available on the open market as merchant sales, an official in the Coal Ministry has said.

Explaining the rationale for liberalising the rules, the official said that merchant sale of excess production would ease pressures on mining leaseholders.

Captive coal mining lease holders are primarily steel producers and thermal power generating companies. Steel companies are reeling under low prices for finished steel and merchant sale from their captive coal mines will assist their cash flow and ease pressures on margins.

As for thermal power companies, their plant load factor is down to levels of 59%, compared with 70% to 75% about a year ago, owing to falling demand for electricity. This, in turn, has resulted in a sharp reduction in dry fuel requirements and excess production from captive mines.

However, the government will make it mandatory that allcoal from captive mines made available on a merchant sale basis, is suitably washed or beneficiated at pitheads in line with government’s focus on ‘clean coal energy’.

Permitting merchant sale of coal from captive mines is also expected to open up a window for leaseholders to leverage the asset and woo fresh investment, the official said.

For example, steel companies, stressed by outstanding debts, would have the option of hiving off the captive mine into a separate entity and inviting foreign direct investment into thecoal mine asset, the official said.

However, he was quick to add a caveat that given the depressed international coal business environment and concerns over climate change in developed economies, appetite for investing in coal assets was not too high either.

A back of envelop calculation indicates that at current average aggregate production from captive coal mines and average consumption of the dry fuel by respective user industries, an estimated 110-million tons of coal could be expected to flow into the open market.

While the changing the rules governing the production and sale of coal from captive mines is expected to have a salutary impact on leaseholders burdened with excess production, no clarity is available as to how government will tackle the issue of more coal flowing into an oversupplied market.

At the moment, Coal India Limited is saddled with pithead stocks of 42-million tons and another estimated 20-million tons are stockpiled at thermal power plants.

Attached Files

More German Coal Plants Face Early Closures as Profits Fade

German coal-fired power plant closures are poised to accelerate as dwindling margins prompt utilities to retire the stations early.

A quarter of hard coal-fired generation capacity in Europe’s largest economy may shut ahead of schedule if plant operators forgo spending on upgrades to keep aging stations open, according to Nena AS, an Oslo-based energy consulting firm. Steag GmbH, the nation’s fifth-biggest power producer, is considering shuttering at least five of its 13 German coal stations before plan, Juergen Froehlich, a spokesman for the utility, said by e-mail.

As German coal plant profitability lingers near its lowest levels in at least five years, other utilities may follow Steag, helping ease a surplus of generating capacity exacerbated by the rise of renewable energy, according to Goldman Sachs Group Inc. While utilities have shut about 18 percent of Germany’s current hard coal-fired capacity since 2011, only 9 percent more is slated to close through 2019, according to consultants Pira Energy.

“You have a lot of old hard-coal plants in Germany and you need to take investment decisions now if you want to continue operating them,” Bengt Longva, a senior analyst at Nena, said by phone.

Dark Spread

The clean-dark spread, a measure of coal-plant profitability, for next month in Germany dropped 57 percent in the past 12 months to EU2.80 per megawatt hour, a third of the five-year average for this time of year, according to broker data compiled by Bloomberg. At the same time, gas-fired generation margins have recovered to 2.86 euros per megawatt hour from minus 8 euros.

“We have seen some resilience for coal, but dark spreads have been narrowing and along the curve I don’t see how these units will be running next year,” said Bruno Brunetti, a director of electricity at Pira in New York. “Recovery of costs is now becoming a real issue.”

While fuel prices have risen this year, coal has climbed faster than natural gas. This spurred a 15 percent jump in German gas-fired generation as of July, compared with a decline of 16 percent in hard-coal plant output, according to German utility lobby BDEW. Hard coal makes up about 18 percent of the country’s generation.

Even with German power prices slumping the lowest in more than a decade, total installed generation capacity has increased by more than 50 percent to 195 gigawatts since 2006 due to the surge in renewables, according to the Fraunhofer ISE research institute. Fossil fuel-plant capacity fell 11 percent in the same period. A gigawatt is enough to power 2 million European homes.

“The industry is reacting at last,” Goldman Sachs analysts wrote in a Sept. 13 note. More utilities may follow Steag’s move, “further improving the outlook for supply and demand,” they wrote.

In addition to Steag’s mooted closures of some of its own plants, the utility and RWE AG, Germany’s largest electricity producer, decided to shut their co-owned Voerde A and Voerde B coal units by April next year.

“What’s happening in Germany is a game of chicken,” said Andreas Gandolfo, an analyst at Bloomberg New Energy Finance in London. “If someone else shuts their power plant first, you benefit.”

Attached Files

China to allow more coal mines to boost output

China will allow more coal mines to boost production within 276-330 operating days, after 74 mines were given the green light to increase output, to ensure supply for winter heating and power generation, sources learned from the National Development and Reform Commission (NDRC).

Besides those identified by China National Coal Association as advanced capacity, coal mines listed as Level I safety mines in 2015 by the State Administration of Coal Mine Safety and those safe and high-efficiency mines recommended by local governments would be allowed to increase output, said official with the NDRC on September 29.

Moreover, due to such restrictions as coal varieties and distance to end users, some coal-producing provinces could select some mines meeting Level II safety standards in 2015 and include them into the category of accommodation, sources said.

Newly-built coal mines that would replace outdated ones would also be allowed to commence operation before the old ones are closed, which could be allowed to shut later than previously required, the NDRC said.

"Such mines (above) would be able to boost production within 276-330 operating days, but other mines must comply with the 276-workday strictly," one source told China Coal Resource.

The latest move was aimed at securing coal supply for heating, gas supply and power generation purpose the coming winter season and next spring, said the NDRC official.

This will be carried out temporarily from October 1 till the end of the year, and assessment will be made based on the market situation to decide when to call off it.

Major coal production bases in China were required to draw up specific schemes, and decide on the mines and their increases of production. The schemes are to be launched before the end of September.

Given the current market situation, coal firms may adopt flexible working hours during the National Day holidays (October 1-7) to ensure supply, after reporting to relevant local government authorities, the official said.

Data published by the State Administration of Coal Mine Safety showed that there were 791 coal mines meeting the Level I safety standard in 2015. So, it is expected that more than 900 coal mines could be allowed to produce within 276-330 operating days.

$1 coal mines turn to jackpots as China’s cuts power rally

Buying bargain-bin coal mines amid the worst commodity slump in a generation has turned into a savvy bet as prices of the fuel surge.

Stanmore Coal bought the Isaac Plains metallurgical coalmine in Australia for A$1 in July 2015 from Brazilian minerVale SA and Japan’s Sumitomo when the price of met coal, used to make steel, averaged the lowest in about a decade and just three years after the mine was valued at A$860-million. One year later, spot prices have soared above $200 a metric ton as China’s steel mills crank out record volumes while its mines slow production.

"It seems like we did get our timing right in this instance," Stanmore CEO Nick Jorss said in a phone interview fromSydney. "When we bought Isaac Plains, hard coking coal was in the $70s. We’ve had pretty substantial movement since then."

Coking coal has surged almost 170% this year as output fromChina, the world’s biggest miner, tumbles under pressure from the government to cut overcapacity even as demand from steelmakers surges. Prices reached $210.80 a ton as of Thursday, according to The Steel Index.

Stanmore, which has seen its share price double since the beginning of last month, isn’t the only miner who bought low.Australia’s TerraCom last week completed the purchase of the Blair Athol thermal coal mine, also for A$1, from Rio Tinto Group as the world’s second-biggest miner exits some of its Australian coal portfolio. Thermal coal in Australia, while unable to match coking coal’s rally, has risen more than 50% this year.

'BRAVE ENOUGH'Miners who struck deals before the recent price surge were well placed to profit from the unexpected revival, even if they’re small producers, said Robin Griffin, research director for global metallurgical coal markets at Wood Mackenzie, a consultant.

"They were brave enough to make the call to try and make it work," Griffin said. "They wouldn’t have foreseen this spike, but they would have had a more optimistic view perhaps. So, in some respects, you could argue their gut feeling was justified."

While the $1 headline price appears a bargain, Griffin notes the deals come with costly commitments. Stanmore is responsible for a $32-million obligation for the Isaac Plainsmine, in Queensland state, while TerraCom is also on the hook for costs related to rehabilitating the mine.

QUARTERLY CONTRACTS

Stanmore is targeting 1.1-million metric tons of coal a year from Isaac Plains, while TerraCom hopes to ship two-million tons annually. Australia, the world’s largest coking coalproducer, exported 186-million tons last year, according to Wood Mackenzie.

Japan’s Electric Power Development, which owned Blair Athol with Rio Tinto and is known as J-Power, said it decided to sell its stake to a company that was willing to recover the remaining coal resources, according to a J-Power spokesman, who asked not to be named, citing company policy.Sumitomo, Rio Tinto and Vale declined to comment.

Stanmore’s Jorss expects coking coal contract prices for the fourth quarter to rise above $150 a ton, from the current quarter’s $92.50. Analysts at Macquarie Group forecast deals will be agreed at $170 a ton, which is still far short of the record of $330 a ton in 2011.

“If they have material to sell, the funds will just roar in this quarter,” Wood Mackenzie’s Griffin said. “If prices continue into the next quarter and into the first quarter of 2017, it will look like a master stroke."

TerraCom chairperson Cameron McRae, a former Rio Tinto executive, said there were good bargains to be found in unwanted coal assets.

"The extent of the commodity down-cycle has put a lot of miners under pressure and you’ve seen companies sell up because their balance sheets require it," McRae said. "When you see a significant down-cycle you will always see assets come onto the market."

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